The Emerald Driller, owned by Vantage Drilling, is contracted to drill in the Gulf of Thailand into January 2011 at $171,000/day. You can’t get that kind of rate now – current going rate for the bigger jackup units ranges from $120,000 to $140,000.

Like most of the rest of the world, the Asia Pacific drilling market has had it rough since the global recession began. Discretionary expenditures at many oil companies were hammered, leading to the cancellation or delay of many projects and drilling programs. “The first half of last year, there was nothing out there. No bids, nothing to bid on. It was like the world came to an end,” said Doug Halkett, chief operating officer for Vantage Drilling.

By the second half of 2009, signs of a turnaround did begin to pop up. “There were a lot of bids toward the end of last year,” Mr Halkett said, and that trend has continued into 2010 at a steady pace.

Seadrill’s West Triton jackup is working in Southeast Asia for Twinza Oil.

Ian Shearer, Seadrill senior vice president, jackups, for the Asia Pacific and Middle East, described the regional market as gradually improving. “We are slowly seeing the early stages of recovery, albeit at a slow pace… In time, as operator confidence grows, we expect to see new campaigns that will impact positively on rig demand,” he said.

Although Asia Pacific is known as a large jackup market, demand for mid-water floating rigs is also picking up, though contracts are usually of shorter duration than before, according to Jim Long, area operations manager for Northern Offshore. “A lot of shorter-term jobs are coming around for medium-depth floaters, and there aren’t many rigs competing for that work. You might have two, three or four bids with some withdrawing due to obtaining other work before contract award,” he said.

“Some contractors have opted to coldstack their rigs as opposed to working them on a short-term basis, and wait for a market that yields some term. The start-up and wind-down costs, along with idle periods in between, make this a viable strategy in many cases. That leaves opportunities for direct continuation if your rigs are already working,” he said.

The fact that the majority of the industry’s newbuild program has been in deepwater and high-spec jackups also means there hasn’t been much expansion of the medium-depth floater niche, he added.

DC spoke with each of these three companies at their Singapore offices to gauge the health of the Asia Pacific drilling market and each contractor’s outlook and plans.

VANTAGE DRILLING

This relatively recently established company – or “a small drilling contractor with growth aspirations,” as Mr Halkett puts it – took delivery of four jackups in the one-year period from December 2008 to December 2009. All are Baker Marine units capable of drilling in up to 375 ft of water and drilling wells as deep as 30,000 ft.

Only one of these four jackups left the Asia Pacific region for the African market: The Sapphire Driller recently finished work for Foxtrot International in the Ivory Coast and took up post in Gabon for Vaalco Energy. Once that project wraps up in September 2010, the rig will return to Foxtrot and the Ivory Coast for another seven or eight months.

Of the other three newbuilds, two have stuck around in Asia Pacific and the third is returning to Asia from Pakistan.

The Emerald Driller is contracted to drill in the Gulf of Thailand into January 2011 at $171,000/day – a rate that Mr Halkett acknowledges was set before the big bust. The going rate now for the bigger jackup units ranges from $120,000 to $140,000, while the smaller 300-ft units can secure approximately $85,000, he said.

The Topaz Driller, just delivered in December 2009, spudded its first well offshore Vietnam for Phu Quy POC, a joint venture company of state-owned PetroVietnam. The contract is expected to run through November this year.

Vantage Drilling’s Platinum Explorer will work for ONGC in India starting in late 2010 under a five-year contract. The rig is under construction at DSME in South Korea.

Finally, the Aquamarine Driller is en route from Pakistan following completion of its maiden well with ENI, to the Philippines to work for an independent Australian company, Nido Petroleum.

“They have two discovery wells that were drilled two years ago. Now they need to go in and do extended well tests. Subject to how those wells flow, this contract could last from two months to two years, but we are hopeful of the latter,” Mr Halkett said.

Now that Vantage has established a record with operating these four jackups, Mr Halkett said, his company is in full gear to prep for the 2010-2011 deliveries of two semisubmersibles and two drillships, one of which is partially owned and three of which are managed assets for Vantage.

The Platinum Explorer drillship, under construction at DSME in South Korea, already has a five-year contract lined up with ONGC. It is equipped to drill in up to 10,000 ft of water, and exploration operations are scheduled to begin on the east coast of India at the end of 2010.

The DragonQuest drillship, also under construction at DSME, is designed to operate in 12,000 ft of water but will be equipped to drill in up to 10,000 ft of water initially. Petrobras has signed it up for eight years and currently plans to deploy it in the Gulf of Mexico.

Vantage’s Sea Dragon I has been signed by Pemex for five years starting in 2011.

The Sea Dragon I and II semis are both under construction at Jurong Shipyard. The first will go to work for Pemex for five years starting in March/April 2011. The second is currently uncontracted.

On the jackup side, Mr Halkett pointed to operators’ growing preference for newer and bigger jackups as an encouraging trend for his fleet of modern jackups.

“I think operators are waking up to the fact that the newer premium jackups can drill wells more efficiently and quicker than the 300-ft jackups built mainly 25 to 30 years ago. As a result, there is a growing bifurcation (in dayrates) between the rig classes, but the operators are evaluating that it is a price worth paying,” he said.

“A lot of people in this area will use big, modern jackups when they don’t need them, water depth-wise, well depth-wise or pressure-wise, to drill their wells. They’re using them because it allows them to drill their wells more efficiently.”

Looking at Vantage’s jackups and where they’re working, he said, most are being used to drill standard wells that could be drilled with 300-ft units. Especially with exploration drilling, a bigger rig that can move efficiently and carry more equipment can make a big difference in time savings, he believes. For example, the Emerald Driller moved 17 times drilling 23 wells in its first year of operations in Thailand last year – with a TRIR of zero and 0.5% downtime, according to Mr Halkett.

“It was bang, bang, bang, bang. I think people have been used to drilling fast wells on the developments in Thailand, but when you’re doing exploration,  you’re moving around… Once a company has used one of these rigs and it’s worked very well, they get used to all these efficiencies. They find it difficult to go back to the older rigs,” he said.

There is certainly a difference in rates between the high-spec jackups and the older ones – approximately $30,000/day to $40,000/day, Mr Halkett estimates. But more operators appear willing to pay that difference.

Unlike this downturn, during the 2000-2001 downturn there hadn’t yet been a significant building of new jackups. “Last cycle, there were no alternatives. This cycle, there is. You don’t have to take the old jackup. You can take the new one, and you’re getting it for almost the same price. Why wouldn’t you? That’s why the big jackup market didn’t go below $100,000 while the small jackups went considerably lower than that.”

Around the Asia Pacific region, Vietnam and Thailand will continue to be high-growth areas for jackups, he believes. Indonesia will, too, although regulatory problems are holding that market back.

“There are a lot of requirements in Indonesia, specifically for big rigs. But there are issues with the local content rules that make it very difficult for operators to actually award contracts. It’s a moving target of what you need to do to get a rig in to operate in Indonesia. That has backed up a lot of work,” he said.

“Indonesia is an improving market and a good market going forward for the bigger rigs. It’s just difficult to get to the finishing line with the operator.”

On the deepwater front, Mr Halkett noted that there appears to be potential activity in countries such as Indonesia, Australia, China and the Philippines. But because there haven’t really been any major discoveries, he said, “it’s always going to be second fiddle to the Golden Triangle.”

He added: “Asia Pacific is an increasingly important part of the world. It will continue to be a very good jackup market, but it would be good if there were some big deepwater discoveries. We could add a fourth leg to that chair, as opposed to three. That would be a game changer.”

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Rig construction: Turnkey is the only way to go

By Linda Hsieh, managing editor

With some of the world’s biggest rig construction yards located in Singapore and South Korea, Asia Pacific has been the birthplace of the bulk of new drilling rigs in this build cycle.

For Seadrill, which has taken on an enormous US$5.5-billion newbuilding program over the past five years, many valuable lessons have been learned in this part of the world.

The West Phoenix was one of four semisubmersibles that Seadrill took delivery of in 2008. Due to the complexity of interfaces on these rigs, Seadrill believes that having them built on turnkey contracts was a factor in their success.

“The biggest challenge for us has been, we were the first in this boom. Our turnkey projects were No. 1 and 2 for Samsung, Jurong and Daewoo. They’re new-design rigs, and the yards hadn’t built anything significant for 10 years. It’s their first turnkey contracts (for drilling rigs),” said Alex Monsen, Seadrill vice president of deepwater projects. From October 2009 to February 2010, he was at the helm of a team that delivered five deepwater rigs in a span of five months.

His team previously delivered eight deepwater rigs over a span of 10 months earlier in this build cycle, and there was an average delay of about three months. But every rig came out on budget, he stressed.

“Turnkey is the only way of doing it because interfaces are so complex now that you need the yard to do it. They have the big engineering organization. Samsung has close to 2,000 engineers; we have maybe 20,” Mr Monsen said.

“It’s the only way to get the yard to take responsibility, even though we’re involved as much as we used to be. But they have to work with the subcontractors and make sure the interfaces are proper,” he continued.

The challenge was that, because these shipyards hadn’t done turnkey projects on drilling rigs before, there was a significant learning curve at the beginning. “We took the brunt of that learning curve,” Mr Monsen said.

Despite early challenges with the shipyards, Mr Monsen acknowledges that the yards have done good jobs overall. In particular, he praised the efficiency he’s seen at the Korean shipyards. “They have the big modern shipyards and infrastructure that you don’t have here (in Singapore)… Here it will take you anywhere between 9 and 10 million manhours to build a sixth-generation semisubmersible. Koreans do it in three. And the West Gemini we’re building now is 1.5 million manhours,” he said.

Another key lesson has been the importance of discipline, Mr Monsen stressed. “We haven’t allowed any significant changes (to rig design). That’s the only way you can deliver these on time… A lot of people are struggling, and my belief is they’re struggling just because of that. You need discipline. You decide what you’re going to build, then you build it.”

SEADRILL

The Norway-based company currently has four jackups working in the Asia Pacific, including in Vietnam and Malaysia. Two more units are set to join this fleet mid-2010, according Mr Shearer, senior VP jackups for Asia Pacific and the Middle East.

Vantage’s Sapphire Driller left the Asia Pacific region for the African market after it was delivered. It recently took up post in Gabon for Vaalco Energy.

“2010 is about recovery from a dramatic downturn in rig utilization. We believe that there will be an underlying improvement in utilization through the year, with bursts of tender activity related to seasonal weather patterns and the annual budget cycle of our clients,” he said. “It will be about linking together work programs of shorter durations than we have enjoyed in recent years, rather than improving dayrates.”

“In the longer term, we see the elasticity of energy demand in developing economies in our region, energy security issues and basic reserves replacement issues as providing a positive outlook for drilling contractors working in the Asia Pacific.”

Overall, he believes that Malaysia, Vietnam and Indonesia will be the region’s high-volume markets, with new opportunities emerging in Australia, Timor Leste and Thailand. “We are watching the development of new or dormant markets such as Cambodia, the Philippines and Papua New Guinea with much interest,” he added.

Mr Shearer also points out that, following the worldwide trend, wells in the Asia Pacific are becoming longer and deeper, influencing factors such as drill pipe specifications and mud system considerations (volume and treatment equipment). “Logistical support is generally more of an issue due to distance to and from point of supply, and increased deck space and variable deck load are valuable features,” he added.

Particularly in the Gulf of Thailand, where total well construction times can be impressively short, there is a special focus on offline capability and increased accommodation manning levels. “We have noticed that with our newbuilds, once operators have experienced the performance advantages, they have a hard time going back to the dependable but ultimately less capable older rigs,” Mr Shearer said.

Seadrill’s West Larissa is contracted to work offshore Vietnam, one of the region’s high-volume markets, along with Malaysia and Indonesia, through 2010.

Despite a trend toward more difficult wells and higher-capacity rigs, however, Mr Shearer said he doesn’t see much action for the much-discussed techniques of managed pressure drilling. “There is a lot of talk about the potential benefit of MPD in terms of overall drilling performance… but we haven’t seen substantive commitment from operators at this time,” he said. Most approaches for MPD here appear to employ “bolt-on” self-contained solutions from specialist vendors, but they have implications for deck areas and payload of units.

“The key issues for jackup rigs seem to revolve around the space and height underneath the cantilever and ease of hookup to existing conventional equipment. In some applications, gas-tight drillstring connections are important,” he said.

Seadrill also has a substantial fleet of tender rigs in Asia Pacific, the world’s biggest tender-rig market. And like the jackup market, this segment took a substantial hit during the last downturn.

“It has been very slow. The last two and a half years, there has been only one new contract signed for tender rigs,” said Alf Ragnar Løvdal, Seadrill senior vice president, tender rigs. That contract was signed by PTTEP of Thailand for one of Seadrill’s newbuild semi-tenders for a one-year term.

Things are picking up, however, with a definite increase in tendering activity by operators, although with shorter contract commitments.

Semi-tenders like the West Alliance, working in Southeast Asia for Shell, offer a cost-effective solution for development drilling compared with jackups, said Seadrill senior vice president, tender rigs, Alf Ragnar Løvdal.

With 16 tender rigs in its fleet, Seadrill accounts for about 60% of the world’s approximately 28 tender units. The company is now building No. 17, the West Jaya, at the Keppel FELS yard in Singapore. It is due for delivery in Q1 2011. As far as activity levels, the two hubs of Thailand and Malaysia take up roughly 10 of Seadrill’s 16 tender units. Brunei and Indonesia each account for one more, and the remainder are located in Africa.

One challenge that the tender market will have to face in the upcoming few years, Mr Løvdal believes, is the number of newbuild jackups coming out. “(Tender rigs) compete against jackups. We feel we offer a cost-effective solution for development drilling compared with jackups, but it’s still competition,” he said.

Oil companies do tend to think longer-term when it comes to development drilling, and that works to the advantage of tender rigs.

“If they have decided to build out the field and have already invested so much money, they continue and complete that. Everybody’s waiting for the oil to be produced,” Mr Løvdal said. “And if they already have the installation up, they want to maintain what they have so they can get as much oil as possible to surface.”

NORTHERN OFFSHORE

Rather than not having enough work to do, as some contractors are experiencing, Northern Offshore’s problem in the Asia Pacific is the opposite: not enough rigs. “One thing that hurts us with getting this work is availability – if we had more assets. Most of the work that comes up, we can’t get it because our rigs are not available,” said Jim Long, the company’s area operations manager.

He’s referring to shorter-term projects for medium-depth floating rigs like his company’s Energy Searcher drillship and Energy Driller semisubmersible. Since some drilling contractors have coldstacked rigs instead of picking up short-term contracts, not many companies are bidding for this type of work, he said.

The Energy Driller is still under a three-year contract with ONGC that will take it through mid-2011. The rig has been carrying out exploration drilling on both the east and west coasts of India. “We just upgraded the rig to be able to work in 1,000 ft of water, and now we’re getting ready to go on a well in that water depth,” Mr Long said. The upgrade primarily involved the mooring system and risers.

The Energy Searcher is working in Vietnam for VietGazprom, contracted to September/October 2010. It’s doing appraisal drilling on a discovered gas condensate field.

“(Vietnam) is an efficient area to operate in. There is a reasonable infrastructure in place, and start-up scheduling is generally driven by well equipment delivery and not a cumbersome bidding process,” he said. “There are a number of exploration programs coming up for jackups and floaters. The area is going to be fairly busy in the next year or so.”

Although the industry is generally still dealing with a downturn, drilling contractors’ operating costs have not fallen much at all, Mr Long commented. “I think it’s because there’s been a lot of consolidation in the oil service and rig equipment sectors. There’s not a lot of competition.” In fact, for some equipment, there’s only a single vendor, unless you look to the non-OEM market.

“The other thing that keeps us from reducing our costs considerably is how we’re going about our business,” he continued.

“We are taking Northern Offshore up to the next level in terms of standards. That means implementing companywide management systems on quality, safety, the environment and operational efficiency. We are doing it in a way that brings value to everyone, to our shareholders, employees, clients and the industry. Maintaining these standards comes at a price, but it is the expectation of our customer, and it will bring returns in a very short time frame.”

This aerial shot shows a Range Resources-operated rig in Washington County, southwestern Pennsylvania, in the hilly Marcellus Shale.

It’s being called everything from a game changer to the new gold rush. Armed with new technologies for tapping unconventional resources, energy companies are pushing the envelope to chase plentiful and increasingly recoverable natural gas in shale plays across much of North America and beyond.

An estimated 16,000 Tcf of shale gas-in-place exists worldwide, according to several studies, including one referenced by a 2007 National Petroleum Council study.

Nearly 6,000 Tcf of shale gas-in-place is thought to exist in North America; 3,526 Tcf in Central Asia and China; 2,547 Tcf in the Middle East and North Africa; and nearly 550 Tcf in Europe. The rest is located primarily in Asia Pacific.

“There is no question that shale gas has become a very significant player in the natural gas arena and one that is starting to sweep the world,” said Kent Perry, team leader for Research Partnership to Secure Energy for America (RPSEA), a research organization managing the largest ongoing  unconventional gas research program in the world.

Union Drilling’s Rig 58 operates in the Marcellus Shale, Lycoming County, in north central Pennsylvania. Some drilling contractors and operators anticipate a move in the Marcellus to pad drilling-capable rigs that don’t need to be moved during the winter.

“We conduct research to determine how much shale gas is available and where it is located, and then we chart a roadmap for tapping those resources by helping to develop technologies and disseminate them into the marketplace,” Mr Perry explained. “The goal of the research is to understand the shale gas that is technically recoverable and convert it into economically recoverable gas.”

New hydraulic fracturing and horizontal drilling technologies, along with systems for addressing water recycling and disposal, have ramped up shale production in the United States in recent years. Now, the industry is examining the potential for shale production in Europe.

But nowhere is the excitement about shale more evident right now than in the expansive Marcellus Shale play in the northeastern United States, and the newest of the plays, the Eagle Ford, in south central Texas.

Both, though still considered exploratory, are deemed to be good prospects for continued growth, believes John Keller, an analyst with Stephens Inc. “From an economic standpoint, we know that shale plays have changed the game for North American drilling and production, but we don’t yet know exactly how the game has changed,” he said, noting that the shale rig count is currently at an all-time high, exceeding 400 in the United States. “The Marcellus is arguably the best natural gas play from an economic perspective,” he continued. “The play’s proximity to big consuming regions leads to higher spot pricing, which helps drive higher returns.”

“A lot less is known about the Eagle Ford in terms of how that formation will shake out, but one aspect that will allow drilling to continue to move forward in the face of weak gas prices is the high liquid content of the play,” Mr Keller noted. “From an operator perspective, there are positives in deploying capital into a play where you are going to get at least some residual liquids production quickly, as opposed to pure, 100% dry gas.”

The Marcellus features around 489 Tcf of recoverable low-density, organic-rich shale a mile or more beneath the surface. It spans at least 30 million to 40 million acres across much of the Appalachian Mountains in Pennsylvania and West Virginia, parts of New York and Ohio, and small areas of Kentucky, Maryland, Tennessee and Virginia. Depths and difficult-to-access mountain areas and narrow roads, bridges and tunnels make the formation challenging for rigs and transportation.

The region’s proximity to several high-density urban markets and an existing pipeline infrastructure make it attractive economically but also pose some regulatory and environmental hurdles, especially for water disposal. Pennsylvania Gov. Edward Rendell has reportedly likened the state to the size of an OPEC country in terms of reserves.

Union Drilling CEO Chris Strong believes that the Marcellus, which currently has between 60 and 70 rigs operating, can reach the 200-rig count, where the Barnett Shale peaked. “But it is going to require some new equipment. We are about out of rigs in other areas of our fleet that we think make sense in the Marcellus market,” he said.

“My view is that the Marcellus certainly looks like the real deal,” said Chris Strong, CEO, Union Drilling, which has 35 rigs operating in the play, 25 of which are smaller, older rigs that were working in the Appalachian Basin before the Marcellus potential was realized.

“We have drilled everywhere from the New Jersey border to eastern Ohio,” he said. “It seems to be one of the low-cost plays, where $3.75 gas is still economical, and that is very attractive to drilling contractors because we can get longer cycle times out of the rigs if we get into a situation like we’re in now, where commodity prices for gas are low.”

The number of large, interstate pipelines and good storage capacity in the Marcellus ensure operators can get their gas to market. “Rights of way and easements for existing, older pipelines are already in place, so if we need high-pressure trunk lines for higher quantities, the regulatory process is not as onerous,” Mr Strong said.

The potential in the Marcellus, which currently has between 60 and 70 rigs operating, to reach the 200-rig count where the Barnett Shale peaked, is “certainly possible,” Mr Strong believes, “but it is going to require some new equipment. We are about out of rigs in other areas of our fleet that we think make sense in the Marcellus market.”

Many newer rigs that were designed for other shale areas are not good candidates for the Marcellus play because the load sizes have to be much smaller, lighter and shorter for the terrain. “The larger loads that are suitable for the Barnett Shale, for example, are very difficult, if not impossible, to permit in Pennsylvania,” Mr Strong explained. “We need rigs large enough to handle the long (4,000-5,000 ft) horizontal drilling lengths, but able to be disassembled into small enough loads to efficiently move around in the Northeast.”

Mr Strong also sees a trend toward pad-drilling-capable rigs in the Marcellus. “If we can drill on larger pads, rather than having 10 locations with multiple roads and gathering systems, the drilling will be less invasive. Also, with the difficult winter in the Northeast, our customers experienced greater delays and loss of efficiency with rig moves than they have in other markets,” he continued. “With pad drilling, we can put a rig on a pad in the fall and not have to worry about moving it until spring.”

Mr Strong believes the industry will continue to build more electric rigs that require fewer, but larger, engines on location that burn less total fuel and have lower emissions. “There are no current requirements in our markets to file a carbon footprint for rigs engaged in oil and natural gas drilling, but lower fuel consumption and lower emissions are pluses for our customers and the environment,” he said.

While environmental issues are being addressed in Pennsylvania, the state is generally on board with natural gas activity because it means more jobs and a growing tax base, Mr Strong said.

Meanwhile, the state of New York is very concerned about environmental issues, with some expressing fears that wastewater produced after hydraulic fracturing may pollute the city’s water system.

“It is common knowledge that there are more regulatory hurdles east of the Appalachians where you have multi-state river basin authorities that have jurisdiction,” Mr Strong noted. “Some of those states are downstream of the Marcellus drilling and are not receiving any direct economic benefits from it. When there is little potential upside, it’s much easier to focus on the potential negatives.”

Water disposal is a universal issue in shale production due to the millions of gallons per well needed for hydraulic fracturing. But in the Marcellus play, the drilling water that contains salts and other contaminants is often trucked great distances for disposal. “In the Barnett, we were blessed with the porous Ellenburger formation, where water could be disposed of in wells 9,000 ft to 11,000 ft deep, beneath the natural gas-bearing formation and far below any freshwater aquifers,” Mr Strong said. “But the formations in Pennsylvania are not as porous or permeable, and wells can take far less water per day. So it becomes prohibitively expensive to dispose the water nearby as opposed to trucking it somewhere else, where it can be disposed of more readily.”

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Europe eyed as next shale nirvana, but regulatory, property rights hurdles loom

By Katie Mazerov, contributing editor

The shale bonanza in the United States has not gone unnoticed in other parts of the world. Efforts are under way in a number of areas, especially Europe, where an estimated 550 Tcf of shale gas is believed to exist, says Bojan Milkovic,  CEO and E&P executive director for INA Naftaplin, who will deliver the keynote address at the IADC World Drilling Conference, June 16-17 in Budapest. The reserves are found in the North Sea Graben, the West German basin, Poland, Ukraine, Romania and the Aquitaine Basin in southwestern France. Limited reserves are believed to exist in Albania, Turkey, Italy, the Adriatic region and Pannonian Basin in Central Europe.

“During the last two decades, the oil industry’s attention has been shifting more and more from conventional to unconventional gas resources,” Mr Milkovic said. “Natural gas is, with no doubt, considered to be one of the most environmentally friendly, cleanest, safest and most efficient sources of energy, and is already well accepted by end users.”

In Europe, the focus is on three main areas: Denmark-Sweden, France and Germany-Poland.

“We are still in the very early stages, but there is definitely much greater awareness of the shale potential,” said Florence Geny, a research fellow at the Oxford Institute for Energy Studies, which is conducting research on the potential of unconventional gas in Europe.

“Close to 50 companies have grabbed land in Europe,” she said. “The next stage will be about exploration and testing before we can move into a development and production cycle.” She said that Lane Energy, in partnership with ConocoPhillips, plans to drill three shale gas wells in Poland by June, and ExxonMobil has announced a drilling plan of 12 wells in Germany in 2010. “With these exploration wells, we are trying to determine if there is in fact gas in the shale and what the quality of the reservoirs are so we can determine the appropriate fracturing techniques,” Ms Geny explained.

Several companies, including ExxonMobil, Marathon Oil, Statoil, Schlumberger and others last year established GASH (World-leadinG innovAtive outStanding straigHtforward), a research initiative to study the potential of gas shales in Europe, particularly the Alum Shale in Denmark and the Posidonia and Carboniferous shales in Germany. The organization recently launched a six-year project to create a European black shale database.

While Europe’s long history of dependence on imported oil and gas has played a role in the heightened interest in shale, the real impetus has been the success of shale production in the United States that has resulted in an increase in reserves, a situation the Europeans have been closely monitoring.

“With the economic recession, spot prices for oil and gas have decreased along with demand,” Ms Geny explained. “But in Europe, gas is supplied under long-term agreements with a price that is oil-indexed. So even though spot prices decrease, long-term prices remain high, and most European utilities find themselves having to import very expensive gas when actually the spot market can supply cheaper gas.

“The real trigger was when Devon Energy cracked the code in the Barnett shale in 2005,” Ms Geny continued. “We’re looking at shale gas as providing security of supply, a way for Europe to try and decrease its dependence on imports and offset declines in commercial gas reserves.” Now, the Marcellus Shale has become the place Europeans are watching to gain greater understanding.

But Europeans face many hurdles in turning potential into reality, not the least of which is cost. “Shales in Europe are deeper, hotter, more pressurized, smaller and more compartmentalized,” Ms Geny said. “And that would increase drilling costs.”

Also, wages are higher in Europe and labor laws more protective and stringent. “And unlike the US, we don’t have a competitive service industry,” she pointed out. “So in the end, it’s a question of price and the relative cost competitiveness of shale gas.”

The land ownership structure is another concern. Unlike in the United States, landowners in Europe own only the surface land, not the mineral rights. “In Europe there really is no alignment between operator interests and private interests because individuals and local communities do not share in the gas profits, so they have no real incentive to support drilling,” Ms Geny said.

“Private owners would be compensated only for use of the land surface, and so they would likely be more concerned with quality of life, the landscape and quality of their drinking water,” she explained. “And before we see Europe really embracing shale gas, the United States would need to clear its own debate on environmental issues,” she noted. “We can import technology, but because Europe is so densely populated, we would need to develop more efficient operations to make the wells more productive.”

Mr Milkovic believes that in anticipating gas shale production in Europe, environmental regulations would likely become even more strict and demanding than they are now. “Host countries and local communities are not ready to let oil and gas companies explore and produce natural gas using unclean or, from an environmental point of view, unacceptable technology,” he said. “So today is the just the right time for the industry to start developing even more clean and environmentally friendly exploration and, equally important, production technologies.”

He cited 3D seismic testing, horizontal drilling and improved fracture stimulation as examples of technologies with significant impact in the last decade. “But in addition to these step-change technologies, continued improvements in core technical areas have been implemented as a result of the industry’s continuing efforts to search for more cost-effective ways to find, develop and operate unconventional gas reservoirs such as tight gas sand and gas shales. New designs in drilling bits, improved well planning and modern drilling rigs have also lowered drilling costs in many regions. Still, further improvements are expected in subsurface imaging  technologies, drilling, logging and completion equipment, as well as production technology.”

Range Resources deploys its water reuse technology at water impoundment sites like the one shown above. The company was instrumental in forming the Marcellus Shale Coalition, which worked with the Pennsylvania Department of Environmental Protection to determine a set of regulations for implementing the technology.

Range Resources, which has 13 rigs operating in southwestern Pennsylvania, last year introduced a water reuse technology that reuses all of the company’s water for Marcellus shale gas development in Pennsylvania, said Ray Walker, senior vice president of the company’s Marcellus Shale Division and chairman of the Marcellus Shale Coalition, an independent group that addresses such issues as water, the environment, education and outreach, regulatory issues, pipeline and infrastructure concerns, among others. The company expects to have 16 rigs operating in the Marcellus by the end of 2010 and 24 by the end of 2011.

“With this technology, we capture the water that flows to the surface after hydraulic fracturing, between 10% and 30%, and put it back into the impoundment. We also capture filtered drilling water and produced water in the impoundments. We then fill the impoundment with fresh water, diluting the salt water,” Mr Walker explained. “That water ends up being 70% to 90% fresh water, which we can then reuse.” By the end of 2009, the industry was recycling 60% of all Marcellus water using this technology.

Range Resources, which has 13 rigs operating in southwestern Pennsylvania, last year introduced a water recycling technology that reuses all of the company’s water for Marcellus shale gas development in Pennsylvania.

Through the Marcellus Shale Coalition, the industry worked with the Pennsylvania Department of Environmental Protection to determine a set of regulations for moving the water around, storing it in the impoundments and constructing the impoundments. “There is a financial incentive to do this because it has actually saved us a lot of money – up to $200,000 per well – on two fronts,” Mr Walker said. “We don’t have to haul the water to a disposal facility, and we have to buy 10% to 30% less water. It also dramatically reduces local impacts from trucks and potential road damage that we are responsible for repairing.”

Range Resources was instrumental in forming the coalition in November 2009. The group has 30 producer members and 40 associate members and represents more than 96% of all Marcellus shale activity in the state of Pennsylvania, Mr Walker noted.

“We are very focused on doing things right, working with conservation groups, private citizens and regulators to make this work for everyone,” Mr Walker said. “I think all of us see the potential here, but we also see the importance of getting out and educating the public about what we’re doing and the state-of-the-art technology we use.”

The steam generator in the Altela system, whose process is driven by low-grade or waste heat rather than electricity.

Altela Inc, based in Albuquerque, NM, has developed what CEO Ned Godshall believes is a radical new solution for removing naturally occurring salts and other contaminants from water that flows back to the surface after fracturing and is produced along with the gas. The AltelaRain system, brought to market two years ago, has been utilized as a mobile unit in the Marcellus where, by continuously removing salts and contaminants, it converts water used for fracturing into water that is less than 50 mg/liter in salt concentration and ten times cleaner than drinking water.

The company’s first product, an 8 ft-by-45 ft portable unit, is deployed at the well site and uses low-grade heat or waste heat instead of electricity, and a non-pressurized technology whereby plastics, rather than corrodible metal, purify the water that can be reused. “If you’re not removing the salts, you’re not solving the problem,” Dr Godshall said, noting that the system is a “win-win” for both the environment and the energy industry because it allows operators to use recycled frac water, instead of fresh water, for subsequent fracturing jobs.

The steam generator in the Altela system, whose process is driven by low-grade or waste heat rather than electricity.

“We are the only economically viable water desalination and water remediation technology that does not use pressure,” he said. “As such, we don’t need pressure vessels, which must utilize expensive metals to reduce the inherent corrosion of pipes, valves, heat exchangers and reaction vessels when they come in contact with the brackish water. Our operating expense is much lower because we don’t need expensive electricity to run the large pumps required to create pressure.”

The mobile AltelaRain system is off-loaded at a BLX gas well site in October 2009.

Altela is building its second product, a centralized, stationary plant in eastern Pennsylvania, to handle much larger volumes and that multiple companies can access. “We can make a water disposal treatment facility small enough in scale so we can have more facilities closer to wells, which reduces the cost of trucking,” Dr Godshall said, noting that the costs of water disposal can be very high in the Marcellus Shale because truckers have to drive great distances to transport the water back and forth.

While the Marcellus appears to be living up to its bounteous expectations, the industry’s eyes are also the Eagle Ford play, which spans from the Mexican border of south central Texas into Louisiana and is considered to be the source rock for the Austin Chalk that lies above it. Compared with other formations, it is brittle and contains high amounts of calcite and silica. The play’s boundaries have yet to be officially determined, but many in the industry believe it holds significant promise, both geographically and economically.

The AltelaRain towers make distilled water from produced water or frac-flowback water using inexpensive plastics that do not corrode like metal components, the company said.

“The interesting feature about the Eagle Ford are the numerous phases in the formation,” said Mike Walen, chief operating officer and senior vice president, Cabot Oil & Gas Corp, which  completed its first well in March and plans to begin additional drilling this summer. “The northern part of the trend appears to be in an oil window where the wells are mostly oily,” he explained. “In the median area, we have a gas condensate window, and a dry gas window farther to the south.”

“We are seeing some great rates from the shale as far as oil production goes, but extracting the liquid out of the shale is more difficult because of the very small pore throat,” he said, noting that the rock is overpressured, which helps push the liquids out. “The economics of the Eagle Ford play have obviously been enhanced by the current price of oil,” he added.

Because the rock contains silica and carbonates, it fractures and props easily as sand does not become embedded in the fracture paths, Mr Walen noted. “The Eagle Ford really lends itself to a resource play because there is not a lot of variability in the rock and pressure regimes,” he said. “It’s all about the repeatability of the reservoir and the execution by the operator to get the hydrocarbons out and thereby, over time, drive down costs.”

Petrohawk Energy Corp has seven rigs in the Eagle Ford and plans to drill several more exploratory wells by the end of the year, said James Redfearn, vice president of drilling and completions. He said Petrohawk’s position in the play, which, unlike the Marcellus, features larger tracts of land without proximity to urban areas, holds an estimated 11 Tcf of resource potential, equating to about 5,600 drilling sites. Petrohawk’s initial acreage was 165,000 net acres, a figure that has more than doubled to 360,000 net acres in the past year.

“Comparatively, the Eagle Ford has a very thick reservoir, maybe 250-ft thick, with a lot of gas per square mile,” Mr Redfearn said. “The thickness dictates that we develop a stimulation program where we contact all of that rock, from the base to the top,” he explained. “The areas with a fairly high condensate yield fit well with today’s pricing, but you have to consider that the relative permeability of the liquids is going to be less than that to gas.”

“The rock may be easier to break down and fracture due to its brittleness and the elements,” he continued, “but at the end of the day, we need a design treatment that will maximize recovery and prop the rock open so the condensate will flow out along with the gas.”

Drilling and completion rigs are fairly well equipped to handle the design of the wells today, but Mr Refearn anticipates techniques will evolve. “Drilling longer laterals, pad drilling and other optimization techniques going forward will require innovation,” he said.

Petrohawk Energy has seven rigs in the Eagle Ford and plans to drill several more exploratory wells by the end of the year, said James Redfearn, vice president of drilling and completions. The company’s position in the play, unlike the Marcellus, features larger tracts of land without proximity to urban areas.

Houston-based Global Energy Services, which designs drilling systems and rig components, recently unveiled its new Ultra rig, featuring a hydraulic rig-walking design that was developed for shale drilling. “With shale, the loads are smaller, and operators typically have to drill multiple wells,” said COO Mike Stansberry.  “With the Ultra, operators can move from well to well without having to rig down. It also leaves a smaller footprint.”

In designing the rig, GES took components from its two existing classes of rigs: the Pioneer, a pad-drilling rig that skids on an X and Y axis, and the QuickSilver, which Mr Stansberry believes is the “quickest-moving rig on the market today.”

“We tweaked existing technology, combined the best features of both and talked to about a dozen drilling contractors,” Mr Stansberry said. The end result was the Ultra. It is designed with four “walking shoes,” one shoe in each corner of a parallelogram, that can pick the rig up, take steps and then set it down. The unit can move up to 40 ft/hour. The rig can be operational in six to eight months, according to the company.

“The Ultra is a four-axis walking system that can move north, south, east and west and at 45° angles,” Mr Stansberry explained. It features a hydraulic power unit placed on the drill floor along with electronic drives that run the engine. “This is important because as you go ‘walking,’ you are carrying all your power sources with you instead of leaving them behind,” Mr Stansberry said.

A mud boom transfers mud from the wellbore back into the mud system.  “We’ve adapted the boom for our rig so that when mud comes out of the wellbore, we have a mud boom that reaches up to 120 ft away so we don’t have to keep moving hoses and modifying,” Mr Stansberry explained.

Safety, mobility, efficiency and economy were the driving forces behind the design. “This rig assembles at ground level, so nobody has to get up in the air,” he said. “It does not require a crane, can move in 26 loads and can rig down, move 100 miles and rig up in 48 hours. That is 10 to 15 loads less than a conventional drilling rig,” he added. “So the cost saving is great.”

While technology continues to advance shale production, the underlying issue that everyone is watching is gas prices, which remain low, especially as the industry moves from withdrawal season into the injection season.

“Whether we have too much supply today doesn’t really matter,” analyst John Keller believes. “But the assumption is that we are going to have way too much supply tomorrow, given the recent acceleration of the rig count coupled with production that never really came down when rigs stopped working in 2009. Based on that, I would say the pricing outlook for the next four to six months is pretty bleak.”

What could impact supply is heightened regulation. “The industry doesn’t seem to have any problems operating the current regulatory environment,” Mr Keller said. “But if new regulations were to significantly drive up the cost of fracturing wells, that could be a game changer in how we develop natural gas in this country. And we could see natural gas prices move materially higher as production wanes and supply is reduced.”

A video interview with Global Energy Services COO Mike Stansberry can be viewed below.

A video demonstration of Altela water desalination system can be viewed below.

IADC celebrates its 70th anniversary in 2010. In recognition of this milestone, and in anticipation of the decades ahead, DC is publishing  retrospectives from issues of decades past. We invite you to explore the the historical contrasts and similarities that may emerge and chart the industry’s evolution through these episodic vignettes. The past is written, and has brought us to 2010. But who knows what the future may hold?

7 YEARS
IADC Houston Chapter contributes to industry, charity
May 2003

IADC Houston Chapter is donating $5,000 to fund the revamping of the Life on a Rig exhibit on the Ocean Star Offshore Rig and Museum in Galveston, Texas. The exhibit will provide the visitors museum with a realistic experience of what it’s like to live onshore. IADC Houston Chapter is asking for donations of photos and equipment for the exhibit. “We are donating $5,000,” said Darryl Smith, IADC Houston Chapter Chairman, and General Manager of Operations for Atwood Oceanics. “We will be donating each year for the next two years.”

The Houston Chapter also donates to a local organization that supports a school for handicapped students, and is also a magnet school for gifted students. This year, the IADC Houston Chapter donated $40,000 to the organization.

19 YEARS
Horizontal well sets German depth record
Dec 1991

WHEN MOBIL Erdgas-Erdol GmbH (MEEG) Drilling decided to drill its first horizontal well, the Hamburg, Germany-based IADC member concluded it might as well set a new record.

So it did.

The Siedenburg Z-17 well, completed during April 1991 and the subject of a recept SPE/IADC technical paper, is the deepest horizontal well ever drilled in Germany. And its TVD of 11,202 ft (3,414 m) makes it one of the deepest in the world.

“After the reservoir engineering aspects of this project indicated a potential five- to eight-fold production increase with a 400-m-long horizontal-completion interval, the drilling and completion aspects were analyzed for technical feasibility,” wrote L. Niggemann of MEEG and R. Ehlers of Eastman Christensen. Their paper, “Horizontal Drilling in Depleted Sour Gas Reservoir,” was presented at the 1991 SPE/IADC Drilling Converence in Amsterdam.

And in addition to the technical drilling challenges, the team had two major safety concerns – sour gas (6.7% H₂S) and under-balanced conditions. Due to previous production out of the zone of interest, the reservoir pressure was only 1,668 psi.

The well was drilled in the depleted Siedenburg field, which has been producing since its discovery in 1964. The well, located 50 miles northwest of Hannover, was drilled at an 85° inclination with a 1,088-ft horizontal section and an overall length of 1,362 ft.

MEEG wanted to maximize gas recovery while minimizing water influx and creating better access to the reservoir by boosting permeability thickness. At the same time, sour-gas production was to be increased to feed a nearby gas purification plant.

The operator contracted ITAG Rig No. 26, a Wirth GH-1500 with 350-ton hookload “(This) fully hydraulic drilling rig proved to be very effective for this application,” the authors wrote. “Drawworks and rotary table could be operated very precisely, which is especially helpful in the harsh downhole conditions experienced when drilling a medium-radius curve in a hard rock.”

35 YEARS
President Ford makes first visit to offshore rig
May 1975

PRESIDENT GERALD M. FORD IS THE FIRST U.S. chief executive ever to pay a visit to an offshore drilling rig.

On April 23, President Ford traveled by military helicopter 96 miles from New Orleans to a drilling site in Grad Isle Block 88. There, in 341 ft. of water, 35 miles off the Lousiana Gulft coast, he toured the sophisticated “New Era” which belongs to Diamond M Drilling Co. and is under contract to Gulf Oil Corp.

The football field-size “New Era”, which cost $28 million, is 290 ft. long, column stablilized, propulsion assisted, semi-submersible rig.

The President was greeted by Diamond M’s president and cheif officer, Don E. McMahon and James E. Lee, president of Gulf Oil Corp.

In a welcoming address to President Ford, McMahon stated that “In order to build and operate sophisticated vessels such as the “New Era”, industry must have a favorable economic environment. That environment must be continuing and long term for industry to make commitments involving hundreds of millions of dollars. The spirit of cooperation between government and industry is essential. We believe that industry, given necessary incentive, can win energy independence for this great nation. We are prepared to do the job- all we need is the opportunity.”

At the completion of McMahon’s remarks, he presented the President with a certificate making him Honorary Head Toolpusher of the New Era.

He remarked, “This is certainly a different and significant operatio and one I wish more people could see, and not only see, but find people to work the equipment…”

44 YEARS
First Turbo-Electric Rig Built by C-E For Dixie Drilling
Jan 1966

The industry’s first turbo-electric drilling rig, the Electrohoist III, is a reality at Continental-Emsco Company’s plant in Houston, Texas. The rig has a rating of over 3,000-hp and is capable of 25,000-foot-plus drilling. Several significant advances in equipment design were used by C-E in building the rig for Dixie Drilling Company of Dallas.

Although C-E initially built a gas turbine-powered rig 1959, this is the first one built specifically for a commercial contract drilling company. A brand new “drawworks,” the Electrohoist III is the industry’s most powerful, the manufacturer explained. Driven by four d-c traction-type electric motors, the hoist will have a rated input of 4200-hp. The substructure and mast are of new design for rig-up and tear-down, and can be transported in a minimum number of truckloads.

Continental-Emsco engineers teamed up with engineers of Dixie Drilling   Company, Solar, a division of International Harvester Company, and General Electric Company to design a single power package for this new giant land rig.

55 YEARS
DEEPEST CABLE TOOL WELL in the WORLD
June 1955

THE WORLD’S DEEPEST cable tool well was abandoned June 3, 1953, by the New York State Natural Gas Corporation at a depth of 11,145! A water zone at this depth filled the hole to 5,500’ and when it became impossible to bail down this water, it was deemed impractical to continue. This deep well was drilled to test the Oriskany sand and the unexplored formations occurring below this producing formation. It was located in Town of Van Etten, Chemung County, New York, 18 miles south of Ithaca and 18 miles north of Elmira.

Approximately $195,000 was expended on this cable tool operation from June 8, 1948, to June 3, 1953. The well was drilled in two stages. The first section was completed August 10, 1949, at a depth of 8,371’ without encountering natural gas in commercial quantities. The well was not plugged at this depth but shut down in order that the rig could be removed and used in other operations. On November 15, 1951, the second or drilling deeper operation commenced and continued until February 27, 1953, when the water zone was encountered at 11,145’. Several non-commercial gas shows were encountered in drilling deeper.

The inital drilling contract was setup on a sliding scale cost per foot basis, increasing in 1,000 foot increments.

Mutual respect key to closing generation gap

Danny Rehg

Fresh out of school in 2007 from the University of Oklahoma as a petroleum engineer, Danny Rehg went to Anadarko Petroleum as a drilling engineer for the onshore group in The Woodlands, Texas.

Swept immediately into various onshore assets in the company, Mr Rehg was given hands-on experience, his favorite project, working 54 days on a vertical pilot well targeting the Marcellus formation in 2008 in Pennsylvania.

“I didn’t realize the challenges of actually getting the well drilled, completed and online,” Mr Rehg said. “It requires people from all kinds of backgrounds, not just engineers. (In the beginning) I don’t think I really appreciated that relationship and the teamwork that’s required in the industry to get that done.”

This field experience paired with Mr Rehg’s willingness to learn and positive attitude has shaped his perception of the industry.

“I think, as an industry, we are in a growth phase. We’re trying to implement new technology and bring new people into the industry. And anytime you have growth, it’s a challenge,” he said.

Using his personal experience as a reference, Mr Rehg reflected on his time with mentor Bill Kinsey, a man he said “is one of the most experienced oil and gas drilling consultants he’s met.”

“The advice and wisdom he had to share with me was very meaningful, and it really opened my eyes to what a great industry this is and gave me hope for continuing a career in the oil and gas business,” he said.

With technology advancing at every turn, Mr Rehg commented that this provides young professionals a great opportunity to step up and be a part of this evolving industry.

“While there’s a lot of technology that is already in the industry, there’s some things we did just like we did 50 years ago. There are a lot of opportunities for young people to create new technology that will help us do it safer, faster, cheaper in the future,” Mr Rehg said.

With a positive attitude, Mr Rehg works in the Marcellus Shale play.

The generation gap has been an escalating concern for industry veterans; according to Mr Rehg, understanding the needs from both parties will help increase communication and could ameliorate training issues.

“I think gaining a respect between younger and older generations is really critical in order for people to work effectively together,” he said. “It’s a challenge, but we have to approach it as a team. It’s not a complex problem in my mind. I think if we can all work together, we can overcome those challenges.”

Mr Rehg expressed hope for the industry to continue to integrate young talent. Anadarko actively recruits engineers from universities around the country. Mr Rehg offered straightforward advice to engineers wanting to enter this industry.

“Be proactive, have a go-getter attitude and work hard. You have to earn the respect of the people you work with,” he said. “Particularly, the older generations – they earned the respect; it wasn’t just given to them.”

He continued, “When you go out to one of our rigs, there’s a lot of young people out working in the field at service companies or for the rig contractor, and those ladies and gentlemen are going to be the leaders of the industry in the future.”

Supplying energy to the world economy is a critical role, Mr Rehg said, and remaining on the forefront of drilling techniques remains an important part of what Anadarko is doing in 2010.

“We’re in a phase right now where we’ve traditionally drilled conventional wells, and we’re moving into more horizontal wells and shale plays,” he said. “It’s somewhat of a transition, but it’s more economical given the current environment.”

Mr Rehg’s pilot well project turned into an exploration drilling operation in 2009. Anadarko currently has four operated rigs working in Pennsylvania shale plays and has plans to pick up more rigs by the end of the year.

Advice from industry legend: Rowan’s Bob Palmer

Bob Palmer

Manpower, machinery, money – three words that summarized how Bob Palmer, former Rowan CEO, remembered his company’s legacy in the drilling industry. Sturdy in these core values, Mr Palmer has always kept his views of the industry economically tied, while trying to practice  strategic planning at Rowan.

“You have to appreciate where we were in the 1981, ’82 time period,” Mr Palmer said. “In 1981, IADC drilling contractor membership went from (about) 350 to over 1,000. In 1982 and 1983, over half the drilling contractors went out of business. Not surprisingly, it was many of those who went into business in 1981. They went in at the crest and fell off at the bottom.”

In 1982 as IADC president (now called chairman), Mr Palmer encouraged “a membership motivated, organized and poised to attack” in a 1982 Drilling Contractor article published that year. He advised keeping this mentality as a way to be prepared for industry challenges, an attitude he also held at Rowan.

“The realities of the unpredictable cyclicality of this business was always taken into account with every business decision and investment decision that Rowan was making, it was always looked at as ‘Well, what if?’ ”

Mr Palmer oversaw the construction of Rowan’s first jackup rig, the Rowan-Houston, in 1968. In 1981, he worked with LeTourneau Technologies to design the large Gorilla and Super Gorilla jackups, a strategic move to gain an edge over competitors with 116C’s or similar-sized rigs.

This picture shows Bob Palmer on one of Rowan’s rigs while he was chairman, CEO and president of the company.

Reflecting on past decades, Mr Palmer commented that technology has given the industry abilities like performing super frac jobs and bringing in shale production.

“Technology is totally, totally different from where we were 20 years ago, and most of that ties back into computers,” Mr Palmer said. “But the biggest single difference is with horizontal drilling. We now, on a real-time basis, can know exactly the orientation of the bit, the angle of the bit, and turn it with downhole motors to accomplish those things.”

As far as key challenges plaguing the offshore industry today, Mr Palmer believes it comes down to the government. “Worldwide, one of the big risks is the goal of the government,” he said. “It’s, ‘What is the government’s position?’ Everywhere that you operate, particularly offshore, the government is your partner.”

Mr Palmer also has concerns about the future of ultra-deepwater drilling, commenting on the idle cost of a deepwater drilling rig. These rigs are for exploratory purposes only, he said, while jackup rigs can be used for exploration, as well as development and workover tools.

“Rowan took a very conservative approach to capital investment, and internally we were never able to justify sending the money to branch out into that type of drilling,” he said.

The industry continues to deal with the waxing and waning of the economy and commodity prices, and Mr Palmer commented on IADC’s role as a mediator to help operators, contractors and service companies address the associated challenges.

During Mr Palmer’s career, Rowan conducted a crane business called Terminator Inc. This photo shows the Rowan New Orleans using one of the company’s 550-ton cranes for removing offshore structures.

“IADC has been able to accomplish issues that help the industry as a whole,” he said. “I think a lot of the joint work that’s been done on health and safety could not have been done without cooperation and effort of all the drilling contractors.”

While this industry is always changing, Mr Palmer’s standpoint on using strategic planning to approach industry problems, discussed in his 1989 paper on the outlook of the offshore drilling industry, has not changed. The paper, “The Outlook on the Offshore Drilling Industry,” was written for the National Association of Petroleum Industry Analysts (NAPIA) in 1989. In it, he utilized the metaphor of a gambler to emphasize his thoughts on handling the cyclical nature of the industry.

“Seek out true market niches, geographic, technical or political, in which there is an opportunity for complete market dominance, at least for a moment in time, and then play to win,” he continued. “As any gambler knows, you have to bet the winning hand when you get them, because it is the only chance you get.”

Click below for video interviews with both Bob Palmer and Danny Rehg.

Lee Hunt, president

To the surprise of the US offshore drilling industry, the Obama administration announced that it will potentially open areas in the mid- and south Atlantic, eastern Gulf of Mexico and parts of Alaska to offshore drilling. While it doesn’t guarantee drilling in these previously banned areas – and even though actual drilling is, at best, four to five years away – this new energy policy still indicates a shift in the paradigm.

At the very least, it is a signal that this administration is recognizing the necessity of hydrocarbons in US energy supply, something that the oil and gas industry has been trying for years to get the government and public to understand. As “clean” as renewable and alternative energies are, it’s fact that oil and natural gas will be the predominant energy source for the foreseeable future, not just for the US but for the world.

For the contract drilling industry, this plan is welcome news, especially in light of the current oversupply in the rig market. Hopefully, if seismics indicate significant deposits on the Atlantic Seaboard, new drilling opportunities will boost the sagging Gulf of Mexico market.

MANY AREAS STILL NO-GO

It’s not surprising that, immediately after Obama’s announcement, environmentalists and their political allies pounced on the news and began bashing offshore drilling. One senator was quoted condemning the plan as a “kill, baby, kill” approach to energy policy. And a press release by the Center for Biological Diversity was already mourning the death of polar bears: “Short of sending Sarah Palin back to Alaska to personally club polar bears to death, the Obama administration could not have come up with a more efficient extinction plan for the polar bear.”

Contrary to what these comments suggest, however, the new offshore drilling plan is not an unqualified win for the E&P industry. There was no mention of the Pacific, including offshore California, which is believed to hold significant reserves. Proposed leasing in Alaska’s Bristol Bay was canceled in the name of environmental preservation, as were pending lease sales in the Chukchi and Beaufort Seas. And whether the Atlantic Seaboard will ultimately be included in the MMS lease sales still hangs on results of environmental impact studies, which will require at least two years to complete. After that, seismic studies will have to be done, another two years at minimum.

What does that mean? Well, for one, polar bears can rest easy for now.

FLORIDA UNDER THREAT

The new offshore plan also keeps the OCS area within 125 miles of the Florida coast off-limits. Yet, the US government doesn’t seem to realize that preparations are under way for drilling just off the Florida coast. Cuba! As that country begins to seriously drill in its coastal waters, IADC is concerned for the safety and environmental protection of the US, Mexico, other Caribbean nations and Cuba itself.

IADC has submitted a request to the US Treasury Department Office of Foreign Assets Control (OFAC) to take a drilling industry delegation to Cuba. This group of offshore technical specialists would conduct an overview of the status of deepwater drilling in Cuban waters and meet with Cuban officials, who would focus on personnel training, environmental mitigation and protection, and accident and explosion prevention. IADC’s first request to travel was denied. A second application, supported by US Democratic Senator Mary Landrieu, was recently submitted.

An environmental disaster borne of insufficient safety and oil spill mitigation offshore Cuba might not threaten polar bears, but it would certainly have disastrous consequences for Florida’s waters, reefs and coastal communities.

The interface between the diamond table and carbide substrate on Baker Hughes’ Hughes Christensen Quantec FORCE PDC bit is optimized for greater durability and thermal stability. By employing finite element analysis, residual stresses were relocated away from the cutting edge.

With the growth of the North American shale plays, it’s not surprising that bit companies are aggressively working to meet the challenges of drilling in the these plays, with new designs or enhancements of existing designs for specific applications.

Several recent designs include new cutter materials for drilling in abrasive or high-temperature formations. Several also feature eight-bladed designs that incorporate new cutter technology and materials, as well as newer bit body materials to increase durability and performance. One result is lower drilling costs for operators.

“A lot of the (bit technology) is a matter of material technology in developing cutters to endure drilling extremely abrasive formations,” said Karl Rose, field engineering manager, Western Hemisphere, for Varel International. “The cutters can drill the transitions between hard and soft rock and interbedded formations without breaking.”

There also have been developments in the material properties of the bit itself, so as the bits become stronger, it allows the designer to push PDC bits into harder types of formations. “With stronger materials, the cutter density can be increased, basically making the bit tougher,” Mr Rose said, “allowing the operator to drill more footage in one bit run through hard and abrasive formations.”

Craig Fleming, technical communications manager with Smith International, agreed: “The better the cutters, the longer the bit can stay in the hole, the more hard and abrasive formation it can drill, and the lower the costs for the operator.”

“We have to begin with a cutter that can stand up to harder and more abrasive formations so we can expand the PDC envelope into those formations,” Mr Fleming said. “On the other side, the more blades on the bit, the more diamond volume can be put on the hole bottom.

“However, we are going to stop with the blade count when the bit is dynamically stable,” he continued. “Smith is at that point now where the focus is on cutter technology, not necessarily higher blade count.”

Reducing trips to change to a roller cone bit and then switch back to a PDC bit, or to replace a lighter-set bit with fewer blades with a heavy-set bit with more blades, saves time and money. Generally, with more blades, the more dense the cutters and the diamond volume, the more durable the bit and the longer it will perform, noted Garrett Pierce, global product champion for directional solutions, NOV Downhole.

“The bit will drill slower in the same rock (compared with a lighter set bit),” Mr Pierce said.

However, it can still save the operator time and money by not having to trip out of the hole to change bits. “For example, if the interval is 1,000 ft, and the bit lasts the entire interval but drills slower than a light-set bit that could only drill 500 ft, then it is less expensive for the operator to remain in the hole the entire section with one bit,” Mr Pierce explained.

Following is a review of several new bit designs and their field performance.

BAKER HUGHES

Baker Hughes’ Hughes Christensen Quantec FORCE PDC bit is the result of examining many bit parameters to improve ROP, durability, stabilization, steerability, ideal loading of the cutter structure and cutter material properties. Finite element analysis was used to guarantee structural and mechanical integrity, and computational fluid dynamics aided evaluation of hydraulic efficiency. Optimized force distribution maintains bit stability and drilling efficiency so all cutters engage the formation uniformly and consistently.

Multiple cutter rows can drill through a variety of lithologies without sacrificing performance. The company’s depth-of-cut control (DOCC) technology provides a stable, low-vibration bit for tool face control. Enhanced diamond volume management optimizes the cutting structure to customize the bit profile and cutter layout to a particular application.

Baker Hughes incorporates a proprietary bit dynamics model and force distribution practice to enhance bit stability. It allows the cutting structure to be loaded more consistently, requiring less energy to drill the hole, optimizing efficiency and stability even at low ROP. Its SmoothCut DOCC technology limits impact damage.

Two new application-specific cutters have been field-proven to be six times more wear-resistant than previous cutters, the company said. The interface between the diamond table and carbide substrate is optimized for greater durability and thermal stability. Residual stresses were relocated away from the cutting edge. Combined with stabilization technology, the risks of extreme and cutter-destroying loading are reduced.

Case history

In the Barnett shale, the new bit drilled 1,873 ft of Atoka sand and Bend conglomerate intervals at an average of 47 ft/hr while holding tangent to the kickoff point. The run saved the operator almost 35 hours and reduced costs by $58,000 compared with offset wells.

In a Limestone County, Texas, well, a 7 ⁷/8-in. Quantec Force Q507FX bit was used to drill through the ratty hard sand and soft shale sequences of the Travis Peak/Cotton Valley transition zone. The bit drilled 1,269 ft at 21.3 ft/hr, 31% faster than the offset well average and 122% more footage than the average of offset wells in a 6-mile radius. The run saved the operator more than 18 hours of drilling time, reducing costs by $24/ft.

HALLIBURTON DRILL BITS & SERVICES

Halliburton’s Drill Bits & Services division’s FX bit uses more erosion-resistant materials from matrix to binder to control fluid erosion with what the company believes is the highest thermal mechanical properties of any PDC cutter on the market. The redesigned blade geometries and nozzle positioning provide greater flow control.

The FX bits include the thermally stable and highly abrasion-resistant X3 cutters, which increases the bits’ ability to withstand extreme heat. A new treatment process significantly reduces breakdown of the diamond cutting structure to help maintain its cutting edge over greater footage, according to the company.

In directional applications, the FX fixed cutter bits complement Sperry Drilling’s Geo-Pilot rotary steerable system and SlickBore matched drilling system. Drilling slope control is enhanced while bit vibration is reduced through impact arrestors that reduce bit bounce and stabilize lateral vibration by tracking between formation ridges in the bottomhole patterns.

Halliburton Drill Bits & Services’ FX bit use more erosion-resistant materials and advanced cutter technology for a highly abrasion-resistant cutter.

For drilling in harder formations, the bit features dual rows of cutters to increase the amount of diamond available to drill without reducing the open face volume of the bit.

Case study

In the Burgos Basin in Mexico, an operator drilling directional wells needed a bit that could increase ROP while drilling the 6 ¹/8-in. section in a single run. Halliburton recommended a 6 ¹/8-in. FMX453Z bit design with X3 cutters. It drilled the entire the 972-m section in a single run, establishing a field record ROP of 70.4 m/hr, 18% faster than the best offset. The section cost/foot dropped from $58.37/m to $21.31/m.

NOV DOWNHOLE

The challenge when running a bit and string reamer assembly is drilling though non-homogeneous formations. This is because the bit and reamer are often in different formations, which can cause the distribution of the applied weight on bit and torque at both the bit and the reamer to become erratic. Add to this lateral and torsional vibration challenges, as well as rig heave in deepwater applications, and correct selection of the bit and the reamer becomes critical.

Typical challenges include the transition of the bit and the reamer cutting structures when a harder formation, or stringer, is encountered. For example, when the bit enters a hard formation while the reamer is still in a softer formation, the majority of the weight indicated at surface is actually being applied to the bit. Similarly, most of the torque is being generated by the bit. As the bit starts to drill the hard rock, the cutting forces change radically, tending to generate lateral vibration. Stick-slip can also be initiated if the increase in torque at the bit is significant.

NOV Downhole’s SystemMatcher bit reamer selection software optimizes the matching of bit and reamer aggressivity and stability.

As drilling continues and the reamer enters the harder rock, the applied weight and torque at the reamer will increase. Conversely, the bit’s weight and torque will decrease. The level of lateral vibration at the reamer tends to increase as the reamer cutting structure enters the higher compressive strength rock. Similarly, the level of torsional vibration (or stick-slip) at the reamer also increases.

The worst-case scenario comes when the bit is in the softer formation and the reamer is in hard rock. Here, most of the applied weight is being taken by the reamer, and the majority of the torque is generated at the reamer. Lateral vibration or whirl is often evident at the reamer. Additionally, the sudden increase in reamer torque can initiate stick-slip. The bit is left with a very low applied weight on bit, almost hanging below the reamer in some cases, a scenario that leads to low depth-of-cut with the associated risk of extreme bit whirl.

The selection of bit and reamer with high lateral stability is essential, as is matching the aggressivity of the two to reduce the magnitude of weight and torque variation between the bit and reamer, particularly where the application contains formations that are interbedded.

To address this, NOV Downhole developed the SystemMatcher bit reamer selection software that optimizes the matching of bit and reamer aggressivity and stability. The type of Anderreamer tool is selected from the database, and the variability of formation strength, expected RPM and ROP ranges for the specific application are entered. From these, SystemMatcher uses logic tables that describe the stability and aggressivity of the drill bit and the Anderreamer tool to match the bit to the selected reamer.

Case study

In the Gulf of Mexico, the ReedHycalog 14 ¾-in. seven-blade, 16-mm cutter bit was selected to match the 14 ½-in. x 16 ½-in. Anderreamer. The interval was drilled achieving all directional requirements with very low torsional and lateral vibration levels. Dull condition of the bit and the reamer showed little wear and no impact damage.

In another well, an operator used a 12 ¼-in. x 14 ½-in. hydraulic Anderreamer with an NOV 12 ¼-in. MSR813S ReedHycalog drill bit, drilling the complete section with very low vibrations. There were no tool failures, and all directional objectives were met.

SHEAR BITS

The Shear Bits 7 7/8-in. SD413E bit drilled the vertical, build and horizontal sections of an entire well in one run. The bit posted a record average ROP of 57 m/hr.

By moving quickly through the bit development process, significant improvements in drilling performance can be realized. One example of the success of this approach was recorded in the western Canadian market, drilling a demanding monobore horizontal well in the Spearfish oil shale play in record time.

The well profile in question included a relatively short vertical section, followed by a tight radius build and a horizontal leg, drilled in one run with a 7 ⁷/8-in. PDC bit. When the Shear Bits team discussed the application with the operator, EOG Resources, the primary challenge was to maximize performance in each section without compromising performance in other sections. Previous PDC bits used in the application showed good performance in the vertical, build or horizontal sections, but never all three.

It was not uncommon to achieve an ROP of over 150 m/hr (500 ft/hr) in the vertical section, where the target build rates in the curve are 8-9°/30 m. Additionally, the horizontal section averages around 700 m in length and was commonly drilled with an ROP well over 50 m/hr. Therefore, a significant challenge existed to develop a bit that could drill the vertical section at a very high ROP, yet be able to record high build rates through the curve and hold angle in the horizontal section without requiring extensive steering.

One crucial aspect matching the design of the bit to the characteristics of the directional tools. Because Shear Bits is not affiliated with any directional company, the company said, it can work closely with many directional companies to achieve this.

Shear Bits custom-designed a 7 ⁷/8-in. SD413E PDC drill bit for the application. The initial performance target was to maximize steerability in the build section while minimizing sliding time in the horizontal leg by inhibiting the tendency to drop or build angle. The design featured an extended, heavily spiraled gauge pad configuration to enhance the bit’s ability to maintain angle in the lateral section and an active cutting structure and gauge configuration for aggressive angle building in the curve.

Four runs were recorded with this initial design, all displaying excellent directional response, but an opportunity was identified to further improve ROP in the vertical section. Over the next six weeks, four designs were developed by building on the results of the previous designs. This led to a series of record wells, the best of which was completed, from spud to rig release, in 3.5 days, nearly doubling the average ROP for the entire interval compared with the first runs with the initial design.

At the beginning of the project, the SD413E was averaging 28-33 m/hr for the well, but after dialing in the optimal design configuration for the application, a record average ROP of 57 m/hr was achieved, including an instantaneous ROP of over 200 m/hr in the vertical section. The aggressive build rates of 9°/30 m were easily managed, and sliding time was held to less than 6% in the lateral portion of the hole.

SMITH INTERNATIONAL

Smith designed an eight-blade 12 ¼-in. bit fitted with backup cutters and optimized blade and nozzle geometry for an abrasive formation on a rotary steerable BHA for a challenging West Africa well.

Smith International analyzed the frictional heat generated at the rock/cutter interface, a critical factor that makes PDC drilling in hard and abrasive formations difficult. The company also analyzed thermal degradation and micro-chipping commonly experienced during long bit runs in deep, high-temperature boreholes.

The study revealed that different applications require different cutter properties. Generally, wear resistance and thermal stability are required to efficiently drill abrasive formations, while a more impact-resistant cutter is best suited for interbedded sections and formations with higher rock strength.

The ONYX cutter technology is the first PDC shearing element to address all three critical longevity issues, including thermal stability and wear/impact resistance, according to Smith. These cutters feature improved thermal properties for greater wear resistance and fatigue life than either standard or premium PDC cutters.

Manufacture of the new cutter technology is a two-step process. First, a premium polycrystalline diamond (PCD) table is made using a conventional HPHT process. The table is then treated in acid to render a catalyst-free diamond disc. This disc is assembled with a tungsten carbide (WC) substrate and subjected to another HPHT process. The end product is treated again to remove infiltrate material from the second HPHT process.

The new cutters’ wear-flats are significantly less per unit rock drilled compared with standard premium cutters. Under cooled conditions, the new cutters removed approximately 130% more rock than the standard premium cutter and finished the test with a better dull grade, the company said. For a similar test without cooling, ONYX cutters drilled 85% more rock than a standard premium cutter with comparative dulls.

Case study

Drilling a 12 ¼-in. hole section in West Africa with PDC bits was producing unacceptable results. The section contained hard/abrasive interbedded sand/shale with compressive strengths over 20,000 psi. Typically, the 12 ¼-in. section requires four to eight bits/runs to complete. In most cases, PDCs were pulled in poor dull condition suffering from ring-out and worn cutters. The initial goal was to drill the section in one run or eliminate as many trips as possible.

Smith engineers designed and manufactured the eight-blade 12 ¼-in. MDSi816 fitted with back-up cutters and optimized blade and nozzle geometry. It was run in a highly abrasive formation on a rotary steerable BHA on wells #2 and #5.

On well #2, the bit drilled the entire hole section from shoe to TD for the first time in field history. The reduction in trip time saved the operator six days, reducing costs by $2 million.

On well #5, the total footage and ROP of the bit more than doubled the ROP and facilitated LWD data capture, eliminating the time needed for post-well logging. Compared with the three-well offset average (six bit runs), the new bit drilled 165% more meters (1,702 m) with an ROP (21.18 m/hr) increase of 122% in addition to completing the hole section in one run.

VAREL INTERNATIONAL

Varel’s six-blade Tough-Drill bit design with full PowerCutter structure successfully drilled the abrasive Hosston formation at an average ROP of 37 ft/hr.

Recently, Varel International has focused on modifying its PDC bit designs to better compete in the Haynesville Shale, with highly abrasive and transitional formations that can lead to early bit failure due to increased wear. A majority of the bit designs in the area face the double-edged trade-off of durability versus ROP.

Varel studied dull analysis of current field-deployed designs and bit records, producing evidence of many bits in the area being pulled for ROP issues. Extensive wear was noted on critical areas of the cutting structure. This investigation led field engineers and bit designers to develop two designs for hard and abrasive formations.

Hard rock applications

For hard rock applications, Tough-Drill bits have proven to reduce impact damage and improve cleaning and cutter-cooling efficiencies.

Based on cutting structure analysis using proprietary software, the PowerCutter cutting structure was deemed the best arrangement for drilling this rock type without sacrificing ROP. This cutting structure provides additional exposure and cutter density on the critical shoulder area of the bit for maximum ROP through hard rock formations, then continue to penetrate harder sand or limestone beds without excessive wear or damage.

Tough-Drill designs are subjected to elaborate computational fluid dynamics evaluations that assist in the elimination of re-grinding and re-circulation of drilled cuttings, common when drilling hard and abrasive applications.

Abrasion-resistant cutters are quality-tested to ensure the proper diamond grain size and thermal stability necessary for these applications.

Case study

Varel was asked by an operator in Louisiana to develop an eight-blade bit with 16-mm cutters for the completion of the 9 ⁷/8-in. interval. The total depth of the interval required drilling through the tough and abrasive Hosston and Cotton Valley formations, where bits commonly wear down quickly. The final 600 ft of the application was through the Bossier formation – a soft shale/limestone where an intact cutting structure would excel.

The main objective was to increase ROP without sacrificing the durability of the current Varel design which had been successful in drilling this formation. Engineers also worked to exploit the benefits of the cutters when entering the shale/limestone formation.

The design incorporated a partial PowerCutter structure with backup cutters situated on the primary blades and tungsten carbide shock studs on secondary blades. This layout provided stability and protection of the main cutting structure for the abrasion and transitional challenges.

For a sharper bit, the cutting structure was loaded with a more abrasion-resistant cutter in order to survive the damaging formations and then benefit from the cutter size in the latter portion of the run.

The bit achieved the objective of drilling 2,339 ft of the section to TD at 10,945 ft with an average ROP of 29.1 ft/hr. The area’s closest offset was pulled for ROP issues after drilling just 600 ft into the Cotton Valley formation. The Varel performance showed an approximate 30% improvement in cost/ft and ROP.

Speaking at a diplomatic meeting in early March in Lagos, US ambassador to Nigeria Robin Sanders took up an industry cause and cautioned the Nigerian government against an “unrealistic timeline” in its local content bill. The bill would establish impossible indigenous quotas for equipment and hiring for the oil industry.

Ms Sanders acknowledged that the bill could address challenges important to the future of Nigeria, such as technology transfer. Yet she also pointed out that some of the timelines of the bill are simply unrealistic. “You have to give the companies enough time to phase out some of their technology to give way to local operators,” she said.

IADC and other industry advocates have been working for the past couple of years to convince the Nigerian government that the bill sets unattainable thresholds for local content, considering the lack of engineering and manufacturing capacity in the country. The bill could also drive foreign oilfield service contractors out of the country, threatening the future of local E&P.

US Ocean Policy Task Force report

Six major oil and gas industry associations, led by API and including IADC, expressed reservations about the “Interim Framework” released by the White House Ocean Policy Task Force (OPTF) on managing coastal and marine spatial planning (CMSP). Industry warned that the framework may conflict with existing laws and discourage adequate offshore oil and natural gas stakeholder consultation.

The trades emphasized the historical role of the traditional offshore energy industry, coexisting with and in many cases enhancing other uses of oceans. Further, they argued that a comprehensive CMSP should enhance access to offshore areas and promote E&P development of new resources. Above all, CMSP shouldn’t become an exercise in prescriptive mapping or zoning. In particular, they warned against using the “precautionary principle,” which are often not based on sound scientific data. Setting the precautionary principle in regulation would violate Congressional intent.

The industry comment was submitted to the chief of the Council on Environmental Quality, which held national public hearings in 2009 on the way forward for developing a comprehensive offshore management plan, now individually under the auspices of MMS, NOAA, EPA and other agencies of the US Department of Commerce.

ISO assessment standard advances

The proposed ISO standard for jackup site assessment (19905-1) has passed balloting at the Draft International Standard stage, with no negative votes submitted. A large number of comments were submitted by the standards organizations of Canada, France, Germany, Netherlands, Norway and Singapore, which will need to be resolved before the standard is balloted at the next (FDIS) stage.

The API PER15K document for HPHT equipment will address both design verification and validation. It will also require a finite element analysis and a fatigue analysis. “Depending on the type of material – whether it has to be inspected on certain intervals or it has to live its full life without being inspected – makes a big difference in how you design it,” said Earl Shanks, chairman of PER15K’s Design Verification subgroup.

Despite the myriad challenges that the industry faces when dealing with difficult high-pressure, high-temperature (HPHT) reservoirs, a couple of existing factors in HPHT completions are already helping to tilt the balance toward in favor of these completions’ safety and reliability.

First, in most HPHT environments, pressure and flow rates decrease over the life of the reservoir, which means the pressures and temperatures applied to completion equipment will decline even as it ages. “Really the worst stresses on your completions equipment generally occurs early in its life. That means it’s brand-new equipment that you just installed and tested. After that, the stress state on that equipment generally declines,” commented Jim Raney, chairman of the API PER15K Task Group.

Obviously, this works to the industry’s advantage as it tries to increase the reliability of equipment working in HPHT environments, which the PER15K group defines as conditions where pressures exceed 15,000 psi or temperatures exceed 350°F, the same definition used by the US Minerals Management Service.

Another factor that helps to support the reliability of completions equipment is the fact that the industry generally uses a dual-barrier concept for completions. “For instance, you have casing on the outside and tubing on the inside. That’s two barriers,” Mr Raney said. “You have the packer on the bottom that protects the casing tubing annulus, and you have a wellhead on top. You also have a safety valve in your tubing plus a tree.”

He continued: “You also have instruments that tell you if one of your two barriers leaks or has a problem. If one of them fails in some manner, you have a second barrier. Then you can reestablish the two barriers before you go back into production.”

Because the industry doesn’t have a long history of operating in HPHT environments, many are concerned about the risk of failure. Yet Mr Raney, who is also director for engineering and technology at Anadarko Petroleum, points out that the industry does have a record of safely working with 15,000-lb pressures. It’s just that these projects have been relatively few, and most of the equipment used were one-off’s typically with smaller-bore diameters than is needed for today’s applications. “Because statistically we’re increasing the number of (HPHT projects), it’s gotten a lot of press. People are looking back and saying, where’s the history on this?” he said.

Equipment and materials for HPHT also have changed drastically over the years. Even if the industry has data and understanding of a piece of HPHT equipment from the 1960s, that doesn’t mean we truly understand the reliability of equipment built in 2007 or 2008. “That’s why we’re trying to do accelerated life testing in order to predict what the performance of that material will be toward the end of its life,” Mr Raney said, part of the validation process detailed in the PER15K document.

PER15K, which stands for “protocols for equipment greater than 15,000 psi,” comprises three subgroups under its umbrella: The Design Verification subgroup, headed by Earl Shanks, Deepwater Technology Company, consulting for BP; the Design Validation subgroup, led by Khedhar Mellah, Chevron; and the Materials subgroup, under Jim Burk, BP.

Because completion equipment – whether it’s the tubing, packers, safety valves or any jewelry on the wellhead – has to stand for the entire life of the reservoir, it’s absolutely critical to understand your reservoir’s parameters before installing the equipment. “What’s going to happen to the composition of your materials as the pressure declines in the reservoir? And if your flow rate declines, the heat from the bottom of your high-temperature well will dissipate, so the temperatures will change,” Mr Raney said. That could change the thermal efficiency of your materials.

The API PER15K HPHT report will level the playing field for competitive analysis when it comes to HPHT equipment because all manufacturers will have one standard to perform to, said PER15K chairman Jim Raney. This graph shows the elements required to complete the equipment manufacturing process.

Indeed, most of the challenges in HPHT projects have generally been materials-related. “We don’t have a lot of data on materials,” Mr Raney commented.

Although there are manufacturing industries outside of oil and gas that use 60,000-lb equipment – and Mr Raney is emphatic that oil and gas companies must learn from other industries in order to advance our own – we must remember that those manufacturing processes are controlled and all elements of the process are known.

“But in the oil and gas business, our operating envelope changes as pressure declines in a high-pressure or high-temperature reservoir. For example, water vapors fall out below a certain temperature or pressure, and different chemical reactions can occur. We need a wider window than other industries.”

According to Mr Shanks, who has been involved with API’s HPHT project since its inception in late 2004, the PER15K document is a novel concept for the API because it doesn’t address specific equipment components. “We’re attempting to address the full scope of drilling, completion, intervention and production equipment, and we’re trying to address it through a systems approach. … Because the loads (in HPHT wells) are so large, you can’t study individual components by themselves. You have to look at the whole system and see what the total system loads are,” Mr Shanks said.

He continued: “It’s absolutely critical for the industry to have reliable designs that can withstand not only extreme temperatures and pressures but also the properties found in produced fluids or completion fluids, Mr Shanks said. For example, some completion fluids that are used to lower temperatures in standard wells can’t be used in HPHT wells because its properties will be broken down or changed.

That’s just one example illustrating that normal rules of the game don’t apply when it comes to extreme temperatures. “Up to about 300° to 350°, there’s a fair amount of experience with equipment presently designed in the oilfield. When you get above 350°, that’s where the properties change for a lot of the common materials we use. Some will lose 5% to 7% of their strength, and that needs to be taken into account when designing your equipment,” Mr Shanks said.

Another problem is that many of the world’s labs can’t fully test these materials to the same pressure/temperature conditions as they will see in the field. “You test as closely as you can to those conditions, but it may require that you only test so far, then use that data to do a computer simulation beyond that. … An example is the subsurface safety valve for a well that’s flowing 25,000 bbl/day of oil. No test facility in the world has that pumping capacity at that pressure so you can test (a valve) that has to be shut-in in an emergency,” Mr Shanks said.

Hydrogen embrittlement needs to be considered in any HPHT design. At pressures greater than 15,000 psi, sour service environment can be attained with very small amounts of sour gas that may be present but can’t be measured. “You have to design for a sour-service environment,” Mr Shanks said. “You have to look at using corrosion-resistant alloys or other materials in your production equipment. … It’s a whole new planning process for the equipment because you can’t measure the two or three parts per million that would make the fluid or gas sour.”

Mr Raney believes that the vast majority of the findings documented in the PER15K document are already being used by the industry. Moreover, most of the gaps identified were “editorial” in nature. “For example, they’ve got a procedure for the approval of a flange, but they didn’t put a 15,000- or 20,000-psi flange in their table. … A lot of the standards were written when no one anticipated 20,000- or 30,000-lb equipment,” he said.

The PER15K group hopes to have a draft of its technical report out for initial balloting by May 2010. Once approved, it will go out to each of the committees for specific components like wellhead or packers. They will be able to study this report, compare it with existing standards for their specific components, then revise their standards for HPHT.

ENI strikes Lower Miocene oil offshore Angola with Nzanza-1, Cinguvu-1

Eni has announced two new oil discoveries in Block 15/06, Nzanza-1 and Cinguvu-1, offshore Angola. Statoil has a 5% interest in this block. Both of the discovery wells, located around 350 km northwest of Luanda in 1,400 m of water, successfully reached the objectives in the Lower Miocene targets, where oil pay sands with good reservoir characteristics were encountered. Operations were completed in December 2009 for Nzanza-1 and in February 2010 for Cinguvu-1. The discoveries will allow the operators to proceed with the currently ongoing pre-development phase of the “Western hub.”

The success of these two wells follow the recent success of Cabaça Norte-1, which had three consecutive oil discoveries in the block in 2009, and five, including Sangos and N’Goma, in 2008.

OEC MOLUs bring offshore to kids

The Offshore Energy Center (OEC) is vigorously pursuing an initiative to bring the offshore industry to classrooms through its Mobile Offshore Learning Units (MOLU). The traveling MOLU exhibit, comprising six self-contained learning stations, journeyed to seven Houston-area schools, as well as others outside the area, during March and April. For more on the program, visit http://www.oceanstaroec.com/education/teachers/molu.htm. DC caught up with the MOLU exhibit at Jane Long Elementary School in Richmond, Texas, in March.

Click below for video of the teaching event, including interviews with teachers and students.

Latshaw Drilling rig goes to Haynesville

Rig 16 is a 2,000-hp, SCR rig with a 500-ton AC top drive and skid system.

Latshaw drilling has released its new Rig 16, a 2,000-hp SCR rig with a 500-ton AC top drive and a skidding system for multi-well pad drilling. The rig went to work in the Haynesville Shale on a three-year contract with Goodrich Petroleum. Latshaw has 14 rigs in its fleet, 13 of which are late-model diesel-electric/SCR units. Within three months, the company will have another rig, Rig 17, completed and available for work.

KCA DEUTAG awarded rig contracts in Libya

KCA DEutag has been awarded two multi-million dollar contracts in Libya by Petro-Canada Oil. One is a one-year contract, with a two-year extension option, for Rig T-72. The 2,000-hp rig will begin operations for Petro-Canada in the fourth quarter of 2010. A one-year contract has also been signed for KCA DEUTAG’s Rig 206 to start in March 2010.

Keppel in joint venture to build, operate shipyard in Azerbaijan

Keppel Offshore and Marine is joining with the State Oil Company of Azerbaijan Republic and Azerbaijan Investment Company to develop and manage a new 52-hectare shipbuilding and ship repair facility in Baku, Azerbaijan. Project construction will span three years.

BP expands acreage in deepwater with Devon buy-out

BP will pay Devon Energy $7 billion for assets in Brazil, Azerbaijan and the US deepwater Gulf of Mexico. These include interests in 10 exploration blocks in Brazil, encompassing seven in the prolific Campos Basin. BP will sell to Devon a 50% stake in the company’s Kirby oil sands in Alberta, Canada, for $500 million.

This deal will give BP a broad deepwater exploration acreage position offshore Brazil, with interests in eight license blocks in the Campos and Camamu-Almada basins, in water depths ranging from 330 ft to 9,100 ft, as well as two onshore licenses in the Parnaiba Basin.

Chevron deploys another drillship in GOM ultra-deepwater

Chevron announced it has commenced operations on Transocean’s ultra-deepwater drillship Discoverer Inspiration in the US Gulf of Mexico. The vessel can drill wells in up to 12,000 ft of water to a total depth of 40,000 ft.

The drillship is the second vessel commissioned by Chevron in the last six months. The Discoverer Inspiration’s sister ship, Discoverer Clear Leader, has already begun work for the company in the GOM.

ExxonMobil to explore Black Sea with specially designed Transocean drillship

Transocean’s Deepwater Champion will drill its first well in the Turkish Black Sea, 2011.

ExxonMobil Exploration and Production Turkey, an ExxonMobil affiliate, will use the Deepwater Champion, a specially designed drillship from a subsidiary of Transocean, to explore the deepwater Black Sea offshore Turkey.

The Deepwater Champion is a sixth-generation drillship capable of drilling 12,190 m in up to 3,660 m of water. The vessel’s derrick contains two drilling stations capable of a variety of simultaneous operations to improve efficiency.  The derrick has two removable sections for more efficient transit under the bridges spanning the Bosphorus Strait at Istanbul.

The double-hulled vessel is self-propelled and capable of maintaining stability in open water in 9-m waves and 70-mph winds. The drillship is currently under construction at the Hyundai Heavy Industries shipyard in Ulsan, South Korea. The drillship will drill its first well in the Turkish Black Sea in the first half of 2011.

CROSCO 3,000-hp rig drilling wildcat in Libya

CROSCO’s 3,000-hp National 801 rig is drilling Well A1-42/4 in Area 42, Block 4, in Jabal Akhdar Uplift, Cyrenaica Platform.

Crosco Integrated Drilling and Well Services has reported the provision of drilling services for Total E&P Libye in Libya. Drilling services are being provided by CROSCO’s 3,000-hp drilling rig National 801 on a wildcat well A1-42/4 in Jabal Akhdar Uplift, Cyrenaica Platform.

“In addition to the drilling services being provided for TOTAL E&P Libye, CROSCO is also providing maintenance and spare part management services on an offshore Libyan production platform. Soon CROSCO is also looking forward to providing drilling services with the two CROSCO 2,000-hp rigs that are in Libya. We look forward to providing all of our clients with knowledge and experience gained from two decades of work in Libya,” Vlado Lescan, CROSCO’s general manager, Libya explained.

Chirag development project green-lighted

The Steering Committee for the development of the Azeri, Chirag and deepwater portion of the Gunashli (ACG) fields sanctioned investment in the new Chirag Oil Project.

The $6-billion development plan is the next step in the ongoing development of the ACG fields in the Azerbaijan sector of the Caspian Sea.

The goal is to increase oil production and recovery through an offshore facility designed to fill a gap in the field infrastructure between the existing deepwater Gunashli and Chirag-1 platforms.

BG Group confirms productivity from Santos Basin test

BG Group has completed a drillstem test (DST) on the Tupi North-East well in the BM-S-11 appraisal area in the Santos Basin pre-salt, offshore Brazil.

The appraisal well confirmed the widespread presence of a light oil- bearing reservoir with high production capacity across the Tupi field.

The results showed record productivity from DSTs on the Iracema well in the same concession area 30 km northwest of the Tupi North-East well. The drilling appraisal area was completed in November 2009.

Statoil discovers oil, gas north of Norne

Statoil has found oil and gas in the Fossekall prospect just north of the Norne Field in the Norwegian Sea. The proved recoverable resources are provisionally estimated between 37 million and 63 million bbl of oil. The volume of associated and free gas is estimated at between 1 billion to 3 billion standard cu m of gas.

Last year Statoil discovered oil on the Dompap prospect, which also lies north of the Norne Field.

Table 1 summarizes the drilling operations for development wells SED-3 and SED-4, which were drilled with intentions to enhance production from the small accumulation of oil in the fractured reservoir of Indonesia’s Sepanjang Field. UBD was used to enable production testing while drilling to identify production zones, as well as to reduce reservoir damage. Both wells were drilled with Apexindo Rig No. 8.

The oil from the Ngimbang Carbonate reservoir in Sepanjang Island, East Java, Indonesia, is composed mostly of heavy black oil with a pour point of 120°F and a wax content of 24.89%. Its specific and API gravity are 0.8574 and 33, respectively, and the bottomhole temperature is 223 °F.

Underbalanced drilling (UBD) operations in this high-pour point oil marginal reservoir, for two wells, SED-3 and SED-4, were planned to achieve the main goals of improving reservoir productivity, avoiding reservoir damage, enabling fracture identification and making testing while drilling possible. Secondary benefits expected by employing UBD included avoiding drilling fluid losses, increasing the rate of penetration and minimizing drilling problems.

This article presents the details as to how the challenges of drilling in UBD mode in a reservoir with high-pour point and waxy oil were addressed in the planning stage and how the UBD program was implemented.

The circulating system for the UBD operation was designed with the ability to heat the fluid system to above the pour point to avoid solidification of the fluid. The drilling fluid was to be heated to 160°F and kept at this temperature to prevent damage to the drilling elastomers. Agitators were installed on all tanks to prevent wax formation.

WEB EXCLUSIVE: Apexindo Rig No. 8 Specifications

INTRODUCTION

Sepanjang is a marginal oilfield that is part of the Kangean PSC block operated by Kangean Energy Indonesia (KEI).

The primary geological objective of drilling operations in Sepanjang is the Ngimbang Carbonate Formation, which is a tight carbonate reservoir located at a depth of approximately 4,500 ft to 4,700 ft VD. The reservoir pressure is around 2,150 psi at a depth of approximately 4,400 ft VD, which corresponds to a maximum pressure gradient of 9.39 ppg.

Historically, three wells have been drilled into the Ngimbang reservoir. The first was exploration well SED-1, was drilled by Arco in 1990. It confirmed the presence of crude oil with high wax content. In 2006, SED-2 and SED-1A were drilled.

To further enhance production from the small accumulation of oil in the fractured reservoir of Sepanjang, two more development wells, SED-3 and SED-4, were drilled in 2008. The main objective was to test the reservoir further southeast of the Ngimbang Carbonate structure.

UBD was used to enable production testing while drilling to identify production zones, as well as to reduce reservoir damage. This article focuses on these two new development wells, drilled with Apexindo Rig No. 8. The well schematics for SED-3 and SED-4 are provided in Figures 1 and 2. Drilling operation summaries for the two wells are presented in Table 1.

PLANNING, PREPARATION

UBD suitability evaluation

To assess the suitability of UBD in drilling the reservoir section of Sepanjang, reservoir data was analyzed using UBD suitability software. The UBD suitability score distribution, which showed a mean score of 45, indicated that the Ngimbang Carbonate is an average to good UBD horizontal well candidate. Based on the current reservoir description, UBD can increase reservoir productivity by minimizing potential damage and by intersecting conductive natural fractures.

Circulation system

The high-pour point oil produced in Sepanjang meant that the active system during UBD operations must be able to heat the produced crude oil and the drilling fluid above the pour point of the crude to avoid solidification of the produced fluid.

Diesel was planned as the drilling fluid for the UBD section. With the pressure gradient of the reservoir at 9.39 ppg, using diesel would render the system sufficiently underbalanced without the need for additional gas injection. Using an oil-based fluid system would also help to reduce any potential reservoir damage.

As drilling progresses, produced crude oil was to be mixed with the diesel as part of the active system. Any excess crude was to be exported to the FSO (floating storage and offloading) facility using the production pipeline.

The diesel and crude oil in the active system was designed to be kept at 160°F for optimal solids segregation and to avoid damaging the elastomers in the rig pump and the kelly hose. The export tank where excess crude will be stored was to be kept at 190°F, ready for export to the FSO facility.

To ensure that well control can be maintained in emergency situations, a kill fluid volume double the hole volume was to be maintained at surface. The kill fluid is a weighted oil-based mud that should not contain any reservoir crude. The IADC UBO/MPD code for these wells is 2-B-5. This is derived from the fact that the reservoir pressure in Sepanjang is only 2,150 psi, meaning the well will flow, but conventional well control procedures still apply, which translates into a Level 2 well classification. Also, the wells will be drilled underbalanced (B) using a single-phase drilling fluid (5).

Bottomhole pressure

The main objective of wells SED-3 and SED-4 was to test the reservoir further southeast of the Ngimbang Carbonate structure using underbalanced drilling. Figure 1 (left) shows the well schematic for SED-3, and Figure 2 (right) shows the same for SED-4.

The 8 ½-in. section of the wells was to be drilled underbalanced at a target drawdown of 50 psi, which is set to avoid water production due to water coning. The reservoir was expected to flow while drilling underbalanced at the planned 50-psi drawdown. Overbalance during drilling was to be avoided to minimize skin damage as much as possible. The wells could also be drilled at balance or at a smaller drawdown to reduce reservoir inflow, if required.

With the drilling fluid density set at 7.1 ppg in order to maintain a 50-psi drawdown, surface choke pressure would need to be applied. Pumping at a flow rate between 350 gpm and 500 gpm, an annulus friction of between 50 psi and 100 psi needed to be factored in as the bottomhole pressure needed to be controlled.

Flow modeling

Figure 3 shows the flow model for UBD operations in Sepanjang. It graphs the bottomhole pressure against different pump rates and choke pressures. The shaded area indicates the operating envelope, where the various constraints during UBD operations are fulfilled. These constraints are minimum annular velocity, min/max motor equivalent liquid volume and the target drawdown.

For proper hole cleaning, the acceptable minimum liquid velocity through the entire annulus was set at 150 ft/min. It also factors in the fact that a 6 ¾-in. drilling motor with a liquid flow rate range of 300-600 gpm was to be used.

Equipment setup, process flow

The main UBD equipment used in the wells’ UBD operations were:

• One unit high-pressure rotating control device.

• One unit choke manifold, sampler and pump house skid.

• One unit horizontal four-phase separator.

• One unit 50-ft flare stack.

• Four units 400-bbl enclosed storage tank with heating coil.

• Two units 400-bbl enclosed storage tank (no heating coil).

• One unit double pump skid for sparging with two 10 HP centrifugal pump.

• One unit centrifugal pump 10 HP.

• Two units centrifugal pump 25 HP.

• One unit centrifugal pump 75 HP.

Figure 3: The flow model for the Sepanjang underbalanced operations graphs the bottomhole pressure against different pump rates and choke pressures. The shaded area indicates the operating envelope, where the various constraints during UBD operations are fulfilled. These constraints are minimum annular velocity, min/max motor equivalent liquid volume and the target drawdown.

The tank farm system consisted of six 400-bbl storage tanks that were used to heat the injection and produced fluid. One tank was used solely for storing and heating clean diesel, which was used for flushing any part of the circulating system that was exposed to the crude and becomes static. Three tanks were used to store and process fluid returns for solids removal and was referred to as the “active tanks.” Two tanks, referred to as “storage tanks,” stored and heated excess crude production that was later reinjected into an adjacent well.

The absence of production facilities in the area constrained the storage capabilities for produced crude during drilling operations, leaving no option but to have crude reinjected into an adjacent well (SED-3), which was also drilled in UBD mode. This practice is not recommended for wells drilled in underbalanced mode, as it offsets the benefits of UBD.

In this case, a hole-cleaning program by coiled-tubing acidizing was conducted later on SED-3, and this restored its production capabilities to the same level as when crude had not been reinjected.

Four tanks were lined with steam coils and heated by a steam generator. Fluid is constantly circulated between the tanks to heat the other two tanks with no steam coils installed. A jet line sparging system, which used two 10 HP centrifugal pumps, was installed on active and storage tanks to prevent wax settling and to circulate fluid between tanks. A 10 HP centrifugal pump was also installed to enable pumping from the active tank to the storage tank or vice versa.

Two CD-500 centrifuges were installed on top of two active tanks to remove solids from the active tanks during the drilling operation, and one CD-600 centrifuge was rigged up with the two storage tanks for further solids removal before the drilling fluid is pumped down the hole.

The two rig pumps were used for fluid injection. One 75 HP centrifugal pump (pre-charge pump) was used to feed the rig pump through a 4-in. pre-charge line. The pre-charge pump was lined up to take supply from either of the six 400-bbl tanks. A 25 HP centrifugal pump was also installed on the pre-charge line, serving as backup to the 75 HP pump, as well as a flush pump for the suction lines for extended hours with no circulation downhole.

Annular returns were diverted from the RCD into the 4-in. 6,000-psi primary flow line, where it was flowed into the 4-in. UBD choke manifold, into the sample catchers and into the four-phase separator. A secondary 4-in. flow line was installed from the rig choke to the separator, and another 4-in. hose was installed from the rig choke to the shale shakers.

From the separator, the solids slurry was shipped via a 2-in. line using a screw pump to the solids-processing system. The cuttings were processed in the grinding tank and were stored in a solids skip, while recovered drilling fluid was sent from the solids-processing system to the active tanks.

As no water production was expected, both the water leg and the oil leg of the separator was lined up for pumping into the active tanks on two separate 4-in. lines. A 20 HP centrifugal pump was also added on the water leg line to allow the separator pumps to keep up with the transfer rate to the active tanks with the rig pump injection rate and reservoir production rate.

Both 4-in. lines were installed with a bypass line to the waste pit in case there was any water production. The gas and the PSV line from the separator was sent to the flare via two separate 4-in. lines. Nitrogen bottles were connected to the separator to maintain positive vessel pressure during the underbalanced drilling operation. The cement pump was connected to the two storage tanks, and the diesel tank and was used to bullhead the drilling fluid down the well through the kill line.

Two conventional non-ported float valves were run immediately above the bit and above the MWD tool in the BHA. In addition, one NRV was run in the string prior to the bit exiting the 9 ⁵/8-in. casing, with additional NRVs placed in the string at increments of 500 ft of hole drilled.

WEB EXCLUSIVE: UBD Suitability Assessment Results

Floating mud cap

Under normal circumstances, the well will not be killed due to concerns with lost circulation and damage to the reservoir. Flowing the well while tripping out with the BHP maintained within the target drawdown of 50 psi will mean that the wellhead pressure (WHP) while tripping will be around 550 psi. With this WHP, a “pipe light” condition exists at around 900 ft, which would require a snubbing unit.

To eliminate the need for the snubbing unit, it was planned that the wells will be balanced using a floating mud cap before any “pipe light” depth is reached. Using this method, overbalance and damage to the reservoir would still be avoided.

In this method, during trip out, the well will be flowed until the bit is inside the last casing shoe. A weighted oil-based mud will then be pumped on the annulus by bullheading through the kill line, with enough mud volume to balance the well, and the WHP will drop to 0 psi.

Tripping can then be continued to surface with no pressure on the wellhead.

IMPLEMENTATION, RESULTS

SED-3 UBD operations

Prior to drilling the 8 ½-in. section, oil-based mud in the well was fully displaced with diesel. The UBD system was then lined up, and hot diesel was circulated down the well through the drill pipe. The initial pump rate was 200 gpm, which was gradually increased to 425 gpm, as required for the MWD tool to transmit a mud pulse.

Gradually increasing the pump rate while circulating was done to observe if the UB system can keep up with a pump rate higher than what was originally written in the drilling program and allowed visual inspection of leaks in the rig-up.

After the UB system was observed to be functional, cement and the entire shoe track were drilled out, and drilling of the 8 ½-in. hole continued while maintaining a 50-psi drawdown.

Drilling of the new formation continued until the presence of shale was observed at 6,428-ft MD and confirmed at 6,493-ft MD. A sidetrack hole was drilled from 5,725 ft down to 6,440-ft MD, where a well test was conducted. The choke was closed for 1.5 hrs to allow pressure to build up in the well, increasing to 290 psi.

The choke was then gradually opened to its fully open position, allowing the well to flow. During the flow test, which lasted 2.5 hrs, there was a 35-bbl gain with a final flow rate of 1 bbl/15 min with a choke pressure of 1.5 psi.

Drilling then continued with the drawdown increased to ± 150 psi until TD for the well was reached at 7,580 ft. Another well test was conducted at TD. The well was shut in for an hour, allowing pressure to increase to 327 psi, and the choke was opened fully. A 592-bbl gain was seen at surface during the 4.75-hr testing period. No significant gas production was seen at surface, confirming the initial assessment that the reservoir has a very low GOR.

After the well test, crude was bullheaded down the well using the cement pump. After tripping out to 2,861 ft and displacing the upper section of the well with oil-based mud to create a floating mud cap, tripping out of the hole continued with 0 psi WHP.

A temporary completion assembly was run to 2,895 ft, which was to be used to inject crude that will be produced when drilling the second well, SED-4.

The rig was then skidded to SED-4, the BOP stack nippled down and the temporary Christmas tree installed. After drilling and completing SED-4, the rig was skidded back to SED-3, and well completion activities immediately followed.

SED-4 UBD operations

After the rig was skidded to SED-4, cement, shoe and new formation for the 8 ½-in. hole was drilled up to 5,590 ft using water, after which an FIT was conducted to 11.8 ppg. The well was then displaced with underbalanced drilling fluid, which was the crude/diesel mix used in SED-3.

Due to the uncertainty with regards to the actual reservoir pressure, it was decided to start drilling the 8 ½-in. underbalanced section at a bottomhole constant pressure (BHCP) of 1,900-1,935 psi, which gives a drawdown of about 200 psi.

UBD commenced from 5,590 ft and continued until 7,170 ft, when KEI decided to conduct a well test. Initial influx was seen at 5,900 ft, and a significant increase in production rate was seen at 6,600 ft, then fully open flow at 7,170 ft.

After the flow test, it was decided to conduct a lateral sidetrack, and drilling of the lateral hole commenced from 5,990 ft. Production was steady until a big influx was seen at 7,032 ft. From 7,032 ft to TD at 7,400 ft, the BHCP was maintained at 2,130-2,140 psi to minimize influx. Drilling was stopped at 7,160 ft to perform another flow test, and the well flowed at an average 600-psi WHP.

Full open flow was not conducted due to insufficient tank holding capacity. It was then decided to continue drilling until shale was seen to confirm the shale boundary. TD was called at 7,400 ft when shale was confirmed. During drilling, all the excess crude produced was injected down SED-3 using the cement pump.

Tripping out to 5,514 ft and bullheading of the upper section of the well with oil-based mud to create a floating mud cap was done, and tripping out of the hole continued with 0 psi WHP.

The completion packer was set at 4,640 ft, and after the completion tubing and Reda pump was run, the BOP and RCD was nippled down. The rig was then skidded to SED-3, and after the Christmas tree was installed, the completion annulus was displaced to a diesel/crude mix, and the completion tubing was displaced to diesel.

WEB EXCLUSIVE: UBD System Process Flow Diagram

CONCLUSION

UBD was used in the Sepanjang Field to drill the 8 ½-in. holes in wells SED-3 and SED-4 in order to achieve the goals of improving reservoir productivity, avoiding reservoir damage, enabling fracture identification and enabling testing while drilling. Secondary benefits include avoiding drilling fluid losses, increasing the rate of penetration and minimizing drilling problems.

In SED-3, the goals of improving reservoir productivity by minimizing, if not totally avoiding, reservoir damage was achieved. Fracture and formation identification was also made possible, enabling the decision of cement plugging the original hole when shale was encountered to be made at the right time.

The goal of enabling testing while drilling was also achieved by allowing a flow test at 6,440 ft. After the first flow test, drilling of new formation continued until TD was reached at 7,580 ft. Another flow test was conducted at TD, confirming that the desired production rate was already achieved, and drilling ahead or drilling a new lateral is no longer required.

The secondary goals of minimizing fluid losses and minimizing drilling problems were also achieved. The goal of increasing the penetration rate cannot be directly proven, but the section was drilled with an average 35 ft/hr ROP without sacrificing hole cleaning.

For SED-4, the objective of production testing while drilling was achieved, as it enabled the operator to correctly decide to stop drilling the original hole and to drill a lateral hole. Drilling the lateral hole was not in the original plan, but data collected during the flow test of the original hole supported the fact that production from the original hole was insufficient; thus the decision was made to drill a lateral hole.

The original hole was drilled underbalanced from 5,580 ft to 7,170 ft, while the lateral hole was drilled underbalanced from 5,990-ft to 7,400-ft TD. The original hole was open and producing during the drilling of the lateral hole. No hole problems were encountered during the drilling of both holes.

The goal of reducing the reservoir damage was also achieved as the 8 ½-in. section was drilled underbalanced throughout the section. The use of the floating mud cap during trip-out was successful, and this avoided the need for a snubbing unit. This technique could be used on future UBD wells where the GOR is small and there is no danger of gas migration.

When the steam boiler went down, there was danger that the UB fluid in the tanks would solidify once the temperature went down sufficiently. This was rectified by adding diesel into the active system to lower the pour point of the UB fluid. It was fortunate that the boiler was repaired after 5 hrs, or it would have required a lot of diesel to dilute the system. It is recommended that a pour-point depressant chemical be available on location to assist if such a problem occurs.

Based on the well objectives achieved and the oil production levels witnessed in the Sepanjang Field, it would be fair to conclude that employing underbalanced drilling in the development of this marginal heavy-oil reservoir is greatly beneficial.

References

Bourgeois, Gilles David, Joanne Chu, Jan Hendrik Terwogt, Awang Kasumajaya Mahran and Alberthnego Wisnugroho: “Under-Balanced Drilling Experience in a Shallow Clastic Oil Field, Offshore Sabah, South China Sea”. SPE Paper 80455 presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition held in Jakarta, Indonesia, 9-11 September 2003.

Park, D., P.R. Brand, B. Allyson and G. Sodersano: “Planning and Implementation of the Repsol-YPF-MAXUS Krisna Underbalanced Drilling Project”. SPE Paper 67689 presented at the SPE/IADC Drilling Conference held in Amsterdam, Netherlands, 27 February-1 March 2001.

Pickles, Rob, Pat Brand and Pat Savage: “Utilization of Underbalanced Drilling Techniques to Exploit a Low-Pressure Reservoir in Indonesia”. SPE Paper 91591 presented at the SPE/IADC Underbalanced Technology Conference and Exhibition held in Houston, Texas, 11-12 October 2004.

Rehm, B. 2002. Practical Underbalanced Drilling and Workover: Petroleum Extension Service, University of Texas at Austin, Continuing and Extended Education, Austin, Texas; United States of America.

This article is based on SPE/IADC 130314, presented at the SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference & Exhibition, 24-25 February 2010, Kuala Lumpur, Malaysia.