Burned once, oil-service companies are playing chicken with producers: show us the money, then we'll show you more iron. This time around, the producers are blinking first. These are heady days again for producers flush with cash for exploration, and oil-service companies anxious to capture a share of those dollars. Rigs at work in the U.S. at year-end totaled nearly 1,500, according to Baker Hughes Inc.'s count-practically every piece of iron in shape for deployment, and, as some producers will attest, some iron that should have stayed in the storage yard. Last year, the question mark over the E&P industry was whether there are any more U.S. prospects worth drilling. Skyrocketing oil and gas prices in 2005-rather than new geoscience-answered that question: at $60 oil and $12 gas, yes, there are still U.S. prospects worth chasing. With tightness in the oil-service space, however, the question now is whether investors in E&P companies can realistically expect a 100-well 2006 drilling program, for example, to be fulfilled. The answer may be "no" for many. While they are posturing for revenues, oil-service operators are not throwing money and people at demand today as they did 30 years ago, when oil and gas prices were last at a level at which producers could throw crazy money at oil-service companies. Instead, most service-company executives report that they're first finding existing technology in their shops to push to the market, implementing low-cost and no-cost ways of increasing product output, and not pouring new workshop floors or fabricating new iron without firm, long-term contracts. "In some cases, small operators are being forced to delay programs one year or more because of the lack of rig capacity," report Lehman Brothers analysts James Crandell and Angeline Sedita in their December summary of a survey of 325 producers. Among problem products and services cited were cementing, completion rigs, tubular goods and fracturing services. Service companies are raising prices. One producer says his exploration budget for 2006 is 25% higher than in 2005, but three-fifths of the additional spending is built in simply for expected inflation in oil-service costs. Where is the producer experiencing service gridlock? "The quick answer is across the board," he says. Geoff Kieburtz, oil-services analyst with Citigroup and who surveyed some 200 producers on their 2006 E&P spending plans, says nearly all the producers expect price increases-averaging some 15%. They have included this in their spending plans. One large onshore producer surveyed managers and field personnel for Oil and Gas Investor and ranked products and services that are not showing up on time or in sufficient quantity: proppant, land rigs, coiled tubing, gas compressors, directional drilling equipment, snubbing services and workover/completion rigs. Other problem areas, albeit less problematic, include pumping, formation evaluation, drillbits and seismic. Service companies are being cautious. As Crandell and Sedita point out, the producers they surveyed would cut their E&P spending plans at $36 oil and $5 gas. The true price threshold? "We believe companies would begin cutting budgets if oil prices fell below $45 and if gas prices fell below $6 or $6.50." Land rigs One producer describes the wait for a land rig "ridiculous." "We had to have one built for us." Other producers are ordering newbuild rigs too. Some 50 of these new orders have been placed with Tulsa-based land driller Helmerich & Payne Inc., with long-term contracts for its FlexRig. They're being built at the rate of two a month. That pace will speed up to three a month this spring and four a month this summer. Hans Helmerich, president and chief executive, says customers' willingness to make long-term commitments for drilling services "provides an encouraging lens on how the industry perceives the unusual longevity of this current cycle." The company began its newbuild FlexRig-design program in 1998, and has put 50 on the market to date; another 50 or more are under way. Although the company has been drilling since 1920, 75% of its fleet has been built new since 1995. "While everyone else was consolidating very old equipment, we were trying to improve the quality and profile of the fleet. We were somewhat the Lone Ranger, and received quite a bit of criticism from our peers. Newbuilds were important to us not just for the sake of new iron but for the sake of new ideas, innovation, safety and the opportunity at the end of the day to drive down customers' total well costs. We fought the notion that a rig is just a rig," Helmerich says. The new-design rig has resulted in faster moves, increased safety records, fewer days on the hole, greater drilling efficiency and lower well costs for producers. Producers report one FlexRig may do the work of 1.33 conventional rigs in the same time. The new rigs come in time for producers' more difficult holes. "The types of nonconventional gas plays that a good group of our customers is involved in are more challenging, and some require limiting the environmental impact." The newest design, FlexRig4, allows for a shallower target (4,000 to 14,000 feet) than FlexRigs 1, 2 and 3, which have a range of 8,000 to 18,000 feet. The FlexRig4 has a no-touch pipe-handling system, a casing running system, and optional air-drilling and skidding packages. The skidding package allows moving the rig on both the X and Y axes, more than doubling the number of wells per pad and cutting in half the pad size or environmental footprint. "We're not taking a mere unit-capacity approach to this demand," Helmerich says. "We're saying that this scramble for rigs is a nice tailwind and it provides important momentum, but what we're trying to do is push on the side of innovation and the side of better ideas, where you're really creating value and unique growth opportunities." Some other new rigs on the market are of a 1960s or 1970s design. "Some industry experts say only one in four of the new-capacity rigs being planned could be considered a high-technology rig. We're in that 25% space. Even in that smaller space, we believe we have the best approach. " Upon bringing online the additional 50 or more FlexRigs that are on order, more than 70% of H&P's U.S. land fleet will consist of FlexRigs. "We're not dragging a fleet that is in large part old and undifferentiated. We're making the very best, newest iron in the business, and it gives us not only a newer fleet profile, but better uniformity and a proven brand from which the customer can expect a certain performance," he says. No matter where the current U.S. land industry cycle is heading, Helmerich believes the market will continue to demand newbuild, new-design rigs, and Helmerich & Payne's current 7% market share will grow. The company does not aim to build new rigs in the future without firm contracts, however. "Our preference and approach today is to capture very good returns. We're seeing today 20%-plus returns on our newbuilds on long-term contracts that come right on top of paying back that investment." The company trained more than 700 people in 2000-04 to work on the FlexRigs. "We have found that people are excited to work on these new rigs, guys who've been around for 20 years and have a chance to work on new equipment." Newer crew members are comfortable with the computerized, joystick-style operation. The drilling data is uplinked at all times to a Helmerich & Payne monitoring center in Tulsa. "We're still mining the opportunities in that. A lot of precision can be achieved with these rigs that you can't get with older equipment, such as steady weight on bit. You're able to bring precision to the effort, driving new performance levels that had not been possible." Customers range from supermajors to small producers. "Some of these unconventional gas plays have long runs-hundreds and thousands of wells-and the smaller customers also understand the prize of reduced well costs and quicker cycle times." Cement "There's not enough cement in the world, and we are short on proppant," Infinity Energy Resources president and chief executive Jim Tuell said at a recent oil and gas conference in New York. The shortages have led the Denver-based producer and well-completions company to form an alliance with Houston-based BJ Services Co. for year-round planning. BJ is well aware of the cement-supply situation. It is testing in-house upgrades of construction cement for use in the oil field. "We historically have used oilfield cement, or API-certified cement," says Ken Williams, BJ president, U.S. and Mexico. But, oilfield cement is a small part of the overall cement-manufacturing industry, which is heavily weighted to making construction cement. There have been predominantly six U.S. makers of oilfield-certified cement, and two were expecting to discontinue making the product at year-end 2005. "Just as our demand for cement has increased, manufacturers have wanted to make less of it to make more construction cement," Williams says. There have been times when drilling rigs have been circulating while waiting on cement. In response, BJ is researching adapting construction cement for oilfield use. "It will require a lot of testing on our part and probably require more additives than we use today. It would definitely be a solution-to get to where we can routinely use construction cement. It's not easy. It's going to be quite a challenge." Without an answer and with expectations of up to 15% more demand for oilfield cement in 2006, he predicts occasional shortages in some locations. The company has also responded with a new-generation cement truck, the Falcon, which is mostly automated. About 50 of them are in the field. "You just program what density and rate you want." For that, there were problems when the trucks were rolled out. "The equipment operators were taking it out of automatic and putting it on manual. They just weren't comfortable with the automation." The operators were eventually convinced to let the computer do the work. "A human cannot mix cement as efficiently and effectively as a computer. We thought about putting some type of throttle lever on it that didn't do anything, just to give the cement operator something to do." To recruit field workers, BJ is offering onshore flex schedules that are more commonly associated with offshore crew schedules-14 days on and 14 off. This is being used now in the Rockies region. Workers from northern California and Montana, for example, are signing on under the offer. "This is something new onshore. It is costlier but customers have been willing to pay for it. We've done that in a couple of locations, and we're looking at doing this in a couple more," Williams says. "As the trend is going to gas wells, gas wells mean deeper and hotter. That means more capacity-more horsepower, more technical fluids, and more frac stages. All of that is requiring us to have more capacity. Gas wells are much deeper. We're talking about more people, equipment and products." Proppant Irving, Texas-based Carbo Ceramics Inc. manufactures ceramic proppant in the U.S. and China and has distribution facilities in North America, Europe, Asia and the Middle East. The company delivered some 190 million pounds of product to its customers worldwide in third-quarter 2005, up 5% from third-quarter 2004. Sales were up 33% in the U.S.; 95% in Mexico, and up 59% in Canada compared with the third quarter of 2004. The company is responding to increasing U.S. demand with a new facility in Wilkinson County, Georgia, that will have an annual capacity of 250 million pounds, a 33% increase to Carbo's existing worldwide capacity, says Paul Vitek, chief financial officer. The facility is scheduled to come online this month and has been designed to be quickly and efficiently expanded in the future, he adds. Abroad, the company is building a new production facility in Russia with an annual capacity of 100 million pounds. This facility is scheduled to come online in late 2006. Besides adding manufacturing capacity, Carbo is using computer simulators and field trials to demonstrate to oil and gas operators that its ceramic proppant, while it costs more than other proppant, increases production and recovery rates, Vitek says. "The increased value of the underlying oil and gas has caused well operators to look for ways to increase production and recovery rates. I expect that this trend will continue." Currently, ceramic proppants represent less than 20% of the total volume of proppants pumped worldwide, but Vitek expects demand to grow "as the industry moves to develop deeper, tighter reservoirs for natural gas in North America and as the use of natural gas expands globally." At BJ Services, which has a patent to pump a lightweight proppant consisting of a resin-coated cellulose and also handles ceramic, bauxite and natural-sand proppants, "we're seeing some tightness," says Williams. "There have been occasions where we have not been able to do a frac job on a certain date because we didn't get the sand." In response, BJ is making commitments to sand suppliers to buy the sand if the plants will expand. And, other suppliers are proposing storage terminals in various hot spots, such as central Texas, the Fort Worth Basin, the Rockies Overthrust, the Permian Basin, Bakersfield, California, and the Appalachian Basin. BJ is also adding new-generation frac trucks, Gorillas, which employ adapted railroad-engine radiators and have more horsepower, so fewer are needed at the frac site. BJ's average horsepower was about 1,200 prior to bringing the Gorillas online; with a Gorilla, its average horsepower is about 2,000, says Williams. The company has built about 50 of these, and all were at work in the fourth quarter. More are under way as part of the company's $400-million-plus capital spending plan for 2006. The higher-horsepower frac trucks are also useful in fracturing more challenging wells. Many wells today are deeper and hotter. They require more horsepower to do a frac job," Williams says. "That's the trend. Gas is driving this. There's no doubt about that. About two-thirds of our revenue now is from gas exploration." Gas compressors Another shortage cited by producers is gas-compression equipment. "It's been a long time since compression and gas plants have been in as great demand as they are today," says John Jackson, president and chief executive of Houston-based Hanover Compressor Co. The reasons include increased environmental regulations and the Kyoto initiative in combination with the heightened pursuit of unconventional gas reserves. "In the past, a producer could pretty much call up anyone and get a compressor or a plant or dehydrator really fast, and that's not the case anymore in many service areas. For the past five years, for example, there has been a surplus of wellhead gas-compression and -dehydration equipment. Due to depressed liquids prices, there has also been a surplus of processing capacity in existing plants along with surplus plants." Hot spots include the Barnett Shale, the Gulf of Mexico post-hurricanes, the coalbed-methane areas of the Rockies, tight-sand gas production and the ArkLaTex region. Jackson encourages customers to plan ahead. Plus, Hanover is collaborating with producers to predict demand, to order components for fabricating equipment in advance of ordering. And, Hanover has initiated an equipment-upgrade program to ready more of its idle compression inventory for service to meet demand. One upgrade results from an industrial-design review. With this, Hanover is squeezing more capacity from its existing manufacturing-facility footprint. The other is the result of bringing in efficiency consultants, and these upgrades get more product through the shop by reducing time on-floor. "Both of those are beginning to bear fruit now in some additional capacity created through either more physical space from a layout change or because we do our job faster," Jackson says. "By making our floor-space utilization more efficient, for example, we have reduced the manufacturing time for our standard 1,200-horsepower package 17%. Thus, we get more product through the same floor space." The company is holding off on pouring more slab."We have focused on being much more efficient with the facilities and labor we have. This is certainly a market we've seen ups and downs in. We're being cautious about adding capacity." Since compression is installed at the end of the well cycle, Hanover has begun to experience the boom in demand for its products only this past year. "I think we have a couple more years left at least. If you look at gas prices, depending on your view of the forecast, I think it could last a while, but given all that, we're still not anxious to add a ton of capacity." Hanover is experiencing compressor orders for both new and old wells. "As wells declined in the past, at $2 or $3 gas, the producer would just plug the well. At $13 gas, the well stays on a lot longer, so there is a need for a lot more equipment. The equipment can last for 20 to 30 years, but it can wear out." Older wells can have greater compression demands. "You're seeing producers drop back reservoir pressures to enhance production. Well, every time you drop pressure at the wellhead, you need more compression. If the pipeline is running 800 or 1,000 psi, if you drop your field pressure from 200 psi to 50 psi so you can get more production out of it, you've still got to stage it all the way to 800. It takes more to go from 50 to 800 than from 200 to 800." Customers also don't want to add that many units; instead, they're ordering bigger ones. "People are trying to be creative." Some of the additional compression demand is also due to the growing complexity of U.S. wells. "A lot of production is coming on from unconventional sources-tight sands, shales, coalbed methane. Those plays tend to require a lot more compression a lot sooner than traditional wells that have higher pressure. So even though U.S. production isn't growing a lot, the need for compression is growing a lot." Hanover is seeing supply shortages from its own vendors. "It is stretching all the way up the supply chain to our suppliers and their suppliers. We're seeing a reluctance on almost everyone's part behind us to add capacity, other than what we're doing-trying to squeeze more down the same shop line. Everyone is saying, 'Let's do what we can do, but let's not go wild here.'" For example, one supplier to Hanover is Caterpillar. "They're very full. Typically we've had maybe a 15- to 20-week cycle time for engines and now they're out somewhere between 45 and 70 weeks for the right engine. The same is happening with compressor frames. One of our major suppliers on compressor frames says that what it used to deliver in six to eight weeks a year and half ago, it's delivering in 44 now." He quotes Hanover's head of U.S. operations who said at a recent planning meeting, "For the first time in a long time, the compression and gas-plant business has changed from a game of checkers to a game of chess. It's become more complicated and requires more forward thinking. We have to do a lot more planning and so do the producers." Some Hanover customers are planning into 2007 for compressors and plants. "Some people haven't been thinking that way yet and it's going to put them in a bind, perhaps in the middle of 2006. They're going to find themselves without the ability to produce their gas very effectively." Tubulars Rising steel costs and demand for steel outside the oil field, such as in construction, have put pressure on oil-country tubular goods (OCTG) prices for some time. Now, supply itself is under pressure. St. Louis-based Maverick Tube Corp. has found in-house ways of increasing output. Its current capacity for producing premium alloy product is about 150,000 tons per year. By the end of this quarter, the company expects to be able to produce 300,000 tons per year, says Bob Bunch, chairman, president and chief executive. The expansion has been low-cost and no-cost. "It's really three-pronged." First, the company has debottlenecked its two existing heat-treat facilities, one in Arkansas and one in Texas. Second, the company has found a third-party vendor to heat-treat about 40,000 tons a year of product for it. Third, Maverick purchased Colombia-based Tubo Caribe in early 2005, and is redirecting some of that plant's premium alloy output to U.S. customers. As for coiled-tubing, which Maverick has been running full out on producing at its Houston facility, it is spending about $12 million to expand capacity about 50%. "We think this will satisfy demand as we see it, but if we're wrong, we'll make adjustments. We're not building any new heat-treat facilities. We're debottlenecking the ones we have," Bunch says. Some of the growing demand for coiled tubing is because its applications continue to expand. "In addition to the traditional downhole, well-workover applications, which continue to be very strong, we're seeing incremental growing demand for coiled tubing, particularly in Canada, for shallow-well drilling applications, and then we've recently developed a flowline application that has some subsea applications. That product line is taking off also." Each expansion in output capability has been weighed against revenue potential. "What is the right amount of capacity expansion to take care of our customers' needs yet be responsible in the marketplace?" He adds that growth in demand for premium alloy products is being driven by deeper well depth and more complicated completions. "And that's a trend we think will continue in the U.S. and Canada, as operators go into deeper and more complicated formations." Rotary steerables At Schlumberger, the U.S. market for its PowerDrive rotary-steerable systems has taken off. Since its introduction in 1999, the high-tier product has been used in directional drilling in high-end, designer 3-D directional wells in the North Sea or in the longest extended-reach wells in the world. Those were the only types of wells for which anyone would consider this type of technology, says Andy Hendricks, Schlumberger marketing manager, drilling and measurements. The issue in the U.S. land market was price-versus-need. Yet, two years ago Schumberger opened a service center for the product in Oklahoma City, and "it's been a real hit." The center has turned out to be Schlumberger's busiest for the tool. Helping has been that Schlumberger has worked with operators to make sure of full utilization of the equipment. "With high-tier equipment like this, it's important that you can maximize utilization." Through the center in Oklahoma City the tools are quickly brought to the well. "Customers use the tools and then we get them off the rig as soon as we can and onto another rig or back to Oklahoma for servicing. From Oklahoma we can easily get to Wyoming and Montana, Michigan, Ohio, West Virginia, South Texas." The technology reduces directional-well drilling time. "One of the uses of the rotary-steerable technology is in a configuration we call Power V for drilling vertical wells. In the foothills of Wyoming and Montana when drilling for deep gas, for example, the rocks underground are very folded and faulted. The rocks are going to push the drilling assembly around and move it where you may not want to go." Traditionally, when the assembly has moved off target, a four-man crew from a directional-drilling company, like Schlumberger, would be called in with more traditional tools, and spend a week or more straightening out the well. "With Power V, we can ship one tool and one person, and in a matter of days we can put the well back on target." Some of the increased demand for the tool is due to tighter North American targets, he adds. "The targets are not directly below where you can spot the rig." The tool is an answer to increased producer demand for more product, and more-efficient product. "It would be real simple just to throw more people and more equipment at the problem," Hendricks says, "but equipment and people are not always the answer and right now they are in scarce supply. "We've had to take a step back and look at the problem in a different way. We can improve the efficiency of drilling in general, so we can drill more wells faster and with the same amount of people and equipment." Pinpoint stimulation Gas prices have producers trying to tap every gas source in their wells, thus pushing up demand for pinpoint stimulation. "Customers are wanting to improve treatment for the most effective amount of net pay they can across the producing zones," says Jim Renfroe, Halliburton senior vice president, production optimization. For this, Halliburton offers its three-year-old CobraMax process, which has seen burgeoning demand growth in North America. In the process, certain sections of zones are isolated and each receives a prescribed fracture treatment. The process is also done fairly quickly. "Equally important is how quickly we can get off the job, so the customer can turn the well on and start getting the results: production." Also, coiled tubing and jet perforating are used with the process, and this eliminates some completion services. "But the real value is in the effectiveness of the treatments as well as the time it takes to do them. It's a much shorter cycle time. The process is also being used in old gas wells where pay has been bypassed," Renfroe adds. While North American reservoirs are unchanged, what producers expect from them has changed. "If you take the Barnett Shale or look at the Rockies, what technology allows you to do is increase production. What we can do now is treat smaller sections of pay. It's not that the wells are more complicated; you can extract more value out of them using technology." The company is also seeing growth in demand for its two-year-old Versaflex expandable liner hanger. "It's a byproduct that came out of an expandable-casing development." Liner hangers can fail when set inside casing. With Versaflex, the hanger is hydraulically expanded against the inside of the casing, creating a reliable seal. The operator doesn't have to go back and squeeze the top of the liner and drill out. "It helps assure that, when you set the liner hanger after you cement the well, you're not going to have leakage around the liner top." Halliburton recently bought some additional innovation-Norway-based Easywell and its swellable elastomers. The patented rubber employs as a bonus what is customarily a drawback of elastomers. "Historically, in the industry we've spent a lot of our time trying to prevent rubber from swelling. In this case, this very innovative company determined that, if you can predict the extent to where the elastomer can swell, you can use it for isolation in openhole or for patchwork inside a casing or other applications." The product is easy to run and doesn't require much manipulation of the casing or pipe. It is activated by the oil-based drilling fluids, which cause it to swell. Uses have been in cementing, and for water shut-off. "We've seen applications for it in smart wells, and we think it has great application for sand-control as well. So it's going to be a technology that we use in a lot of our portfolio throughout Halliburton." Offshore rigs Houston-based offshore driller Transocean Inc. has partnered with Calgary-based Tesco Corp. on its casing-running and casing-handling systems. "It has helped us eliminate some downhole problems and casing problems, eliminating a lot of lost time our customers might see and significantly improving the safety of the operation," says Mike Hall, Transocean vice president, engineering and technical services. Without expanding its fleet, Transocean is looking at low-cost or no-cost ways of adding capacity, such as more advanced planning with customers, Hall says. "How can we optimize the design of the well to better utilize the capabilities of the rig in question?" Key equipment and processes include top drives, pipe-handling systems and subsea equipment. To improve the foremost, Transocean plans a next-generation top drive or derrick drilling machine with Aker Kvaerner MH. Design is under way now, and a prototype unit may be on a rig in early 2007. "With it, we can drill with higher loads, at higher torque and higher speed." Also, maintenance of the unit is to be easier, and it can be repaired more quickly in the field. "It is a modular unit that, instead of taking five to seven days to take a machine out of the derrick, repair it and put it back up, we can change out modular components in a matter of hours." To the customer, drilling time could be reduced as much as 8% from top-drive and subsea performance improvements. "Subsea problem time has run from 3% to 7% by itself, depending on the rig and the kind of well that is being drilled. We hope to be able to eliminate most, if not all, of that. To the customers, they will be able to drill wells in fewer days and at a much reduced cost." From a procedure standpoint, these innovations would put Transocean operating as fast as it can, and its equipment at capacity. "Equipment is the limitation that we're running into," Hall says. "We've matched the drawworks and the pipe-handling system, the power slip, the iron roughnecks, and the next step really is a significant improvement in the capability of the equipment. "That's why we've embarked on this derrick drilling machine effort with Aker Kvaerner MH. That's why we're partnering with Tesco. They have some technology we want to use to improve overall efficiency for ourselves and our customers." As for fleet expansion, Hall says Transocean is gauging customers' interest and demand for deepwater drilling rigs. The right dayrate and a long-term commitment are normally required to justify new construction. "We are hearing from some of our customers that they anticipate needing rigs that are not in our fleet or a competitor's fleet. There are some vessels being built worldwide that may fill some of those needs. But we are seeing interest that may generate the opportunity for us to participate in a new building market." Planning Houston-based rig-equipment manufacturer National Oilwell Varco has a backlog currently of $1.7 billion-significantly higher than two years ago. "We may take a little longer to deliver something now than in the past, but there is no gridlock," says Pete Miller, chief executive. A lot of the hold-up is at the shipyard, where offshore rigs are being built. "If you order a jackup rig today it's going to take two or 2.5 years to get it," he says. The critical path to expediting this process would be that of the shipyard, rather than the oilfield machinery- and equipment-makers like National Oilwell Varco, he adds. "This industry has been in such a depression for 20 years, customers were accustomed to calling for equipment without regard for production lead-time. Today, with the increased demand for equipment, it is essential for all of us to adapt to the changing level of planning required. There was so much overcapacity in the past 20 years that the industry didn't have to learn about planning. It's not a terrible situation. We, the industry, just need to get back to the basics." Much of the industry's equipment and infrastructure needs to be rebuilt, he adds. "The average drilling rig out there is 25 years old. They don't run forever. What you're seeing right now is a combination of demand for increased capacity and for different capacity. You want better technology. We are in both a process of a capacity increase and a replacement of capacity." Hanover's Jackson says, "It's taking a lot more forward thinking by ourselves and our customers to say, 'This is the box we live in.'