Going from Louisiana to Tunisia after graduating from Northwestern State University in 1976, Larry Holloway was excited about his first international offshore rig assignment. It wasn’t his first trip offshore – he is a second-generation roughneck as his father, Shelton, was VP operations for Penrod Drilling, and had his first trip offshore with his father when he was only 12 years old. He had also put in consecutive summers on offshore rigs during high school and college, even working his way up to a derrick hand.

Still, it was his first trip abroad. Moreover, his company had provided few details about the trip or even where exactly he was going. After arriving in Africa, Mr Holloway was met by a local Tunisian holding his name on a small sign; however, the gentleman could not speak English. He was then put into a taxi, driven by another local he was unable to communicate with. “At times during that seven- or eight-hour ride through the desert, I thought I might have possibly been kidnapped,” he recalls.

Fortunately, it turns out that he had not been kidnapped but was being taken to meet the local area manager. Yet the story clearly illustrates just how much the industry has improved in the three decades since. Nowadays, employee communication and training is seen as vital to a company’s HSE performance.

“Back then, you were just expected to know how to do things and you had to figure it out on your own. We’ve gotten so much better at teaching and training our people,” Mr Holloway said.

The same goes for safety and the environment, he said. “We’ve changed significantly and made tremendous efforts to have incident-free and environmentally safe operations.”

Take Chevron, for example. Atwood Oceanics’ VICKSBURG jackup, for which Mr Holloway is operations manager, has been drilling for Chevron in the Gulf of Thailand since 2006. The operator’s commitment to safety has been truly impressive, he said.

“They have the same respect for safety as we do at Atwood. They don’t just talk about safety; they walk the talk. They want everything to be done incident-free. If it requires shutting an operation down in order to be incident-free, they’d rather you do that than have anyone get hurt,” he said. “They believe that no one should get hurt, and that makes my job a lot easier.”

A GOOD NAME GOES A LONG WAY

Because he had already built up his rig experience during school, it didn’t take many years for Mr Holloway to work his way up to toolpusher/OIM after that first roughneck assignment in Tunisia. And over the last 32 years, he’s created an impressive resume with Penrod, Chiles Offshore, Noble Drilling and, since 1995, Atwood Oceanics. Areas where he’s worked include Tunisia, Malaysia, Vietnam, Australia, Trinidad, Myanmar, the Philippines, Brazil, Japan, Alaska, Gulf of Mexico, Nigeria and Thailand, to name a few.

“I think I’m well respected by my peers. Operators know who I am, and if I’m running an operation, they want to have the rig I’m looking after,” he said.

Mr Holloway notes that a global career such as his requires not only the flexibility to quickly pick up and move halfway around the world, it also calls for minute attention to cultural differences – which can be sometimes obvious and sometimes subtle. When he brings in new employees from the US or Europe, he makes sure they have some cultural understanding. “They have to understand how to treat people according to a different set of cultural rules. For example, don’t point your finger. Never touch them on the head. Don’t talk loudly because they’ll think you’re being aggressive. It has its challenges.”

In Southeast Asia and Bangkok, Thailand, where Mr Holloway has been based for the past seven years, people tend to be shy and quiet. “It’s difficult sometimes to get them to speak out, and they don’t usually volunteer much information. But they’re very good workers and extremely friendly. People call Thailand the Land of Smiles, and that’s true.”

NOV Elmar has opened a new facility in Dubai, expanding its premises in the region to almost 40,000 sq ft and increasing staff to over 50. The facility, located in Jebel Ali, enables the firm to manufacture wireline units and trucks on site in Dubai, as well as expand its original operations associated with the service and rental of wireline and coiled tubing equipment.

As part of the expansion, NOV Elmar Middle East has launched a service and repair centre and appointed Pete Davis to head up the new division. A first for the Middle East, the new division will allow the firm to carry out annual and major service work on coiled tubing equipment.

Alistair Ellis, general manager, NOV Elmar Middle East, said, “Over the past five years, NOV Elmar Middle East has grown considerably, and we now have the resources in place to meet the increasing demand for our products from customers in the Middle East and Far East.

“Our Well Head Equipment Team has recently completed the manufacture of a wireline winch for the Elmar Far East Fleet, which is the first of its kind to be manufactured in Dubai. By manufacturing our products as close to their final destination as possible, we are able to improve delivery times and provide an increasingly efficient service to our customers.”

National Drilling & Services Co of Oman names new CEO

National Drilling & Services Co (NDSC) of Oman, a subsidiary of United Gulf Energy Resources (UGER), has named Ashwani Sethi as its new CEO. This announcement comes as the company prepares for an expansion of its onshore rig fleet. NDSC presently operates four land rigs in Oman.

Mr Sethi previously worked with NDSC during the Lekhwair Turnkey, a “Drilling in the ’90s” project for Petroleum Development Oman. Pat O’Shaughnessy, formerly group general manager, remains with the company in a new position as consultant to the Board of NDSC.

VP international sales & business development joins BJ Services

BJ Services announced that Juan Carlos (JC) Mondelli has been appointed vice president of international sales & business development. He has more than 37 years of management experience in operations, marketing and sales.

Separately, BJ Services has formalized its global Shale Technology team. The group will focus on the research, development and delivery of shale technology solutions to customers operating in shale oil and gas reservoirs.

Chevron awards support vessel contract to Remedial Offshore

Remedial Offshore was awarded a multi-year contract from Chevron Offshore (Thailand) to provide an elevating support vessel (ESV). The vessel will support implementation of various brownfield optimization initiatives. The two-year contract will commence next year between 31 March and 31 May. Remedial has two ESV units under construction at shipyards in China.

Pride appoints Randy Stilley CEO for mat-supported jackups

Pride International announced that Randall D (Randy) Stilley has been appointed to the position of CEO of Pride’s mat-supported jackup rig business and will join the company immediately. Mr Stilley is a 32-year veteran of the oilfield services industry. He previously served as president and CEO of Hercules Offshore, leading the company through an initial public offering and the acquisition of TODCO. Before Hercules, Mr Stilley served as president and CEO of Seitel and held management positions with Weatherford International and Halliburton.

Cudd hires well control engineer

Alex Korzenewski has joined Cudd Well Control, a division of Cudd Pressure Control, as senior well control engineer. He has over 31 years of drilling and completions experience. He previously was at Weatherford International, where he held several positions, including project manager and senior underbalanced drilling engineer. He is a registered professional engineer in the state of Texas.

Mautz, Fontenot named InterMoor QHSE director, QA/QC manager

InterMoor has named Randy Mautz as quality, health, safety and environment director and Chuck Fontenot as quality assurance and quality control manager. Mr Mautz has over 20 years of experience in quality management. He will be responsible for the coordination of all of InterMoor’s quality, health, safety and environmental issues worldwide. Mr Fontenot has 13 years of experience and will be responsible for the oversight of the day-to-day functioning of the company’s US quality program.

MB Century lauded for safety campaign

MB Century has won the National Safety Council of Australia award of excellence for the best communication of a safety message. The award recognized the company’s Safety at Work & Home campaign, which aimed to communicate a message of safety not just at work but also to employees’ families at home. Details about this campaign were featured in the Sept/Oct 2008 issue of Drilling Contractor.

Boots & Coots signs Africa deal

Boots & Coots International Well Control has signed a new Safeguard contract worth $45 million for a term of up to 36 months in North Africa. This significantly expands the company’s risk management and prevention services in the country.

WesternGeco wins major GAZPROM contract

WesternGeco has been awarded a major land contract by Gazprom Libya for the acquisition and processing of 3,400 sq km of 3D seismic data over the Ghadames Basin. Gazprom selected the Q-Land high-channel-count, integrated point-receiver acquisition and processing system to acquire the data. Q-Land enables the WesternGeco single sensor technology, resulting in effective noise attenuation and improved data quality.

Also selected is the Maximum Displacement Sweep (MD Sweep), a complementary methodology that enables a seismic vibrator to produce more energetic low frequencies than a traditional sweep design approach, to both increase seismic bandwidth and image deeper targets.

New formation evaluation tool available from APS Technology

APS Technology has introduced WPR, a compensated geometry, dual-frequency (400 kHz and 2 MHz), dual spacing formation evaluation tool for LWD and measurements-after-drilling (MAD) services in all well types.

WPR operates in all mud types, including oil-base and salt-saturated, and provides real-time resistivity with flexible transmission formats. High-resolution data is stored in downhole memory, which can be retrieved and processed during trips. Downhole storage in the WPR is 32 MB, with an additional 32 MB in the MWD tool. Memory fill-rate of downhole WPR + Gamma data is 8 MB or less in 120 hours, which can be downloaded in about 10 minutes during a trip.

Applications include geosteering, correlation, pore pressure trend analysis, casing point selection, wireline replacement, logging while tripping and logging with and without the flow switch enabled (for air and foam-drilled wells). Remote access capabilities include diagnostics, real-time and post-survey transfer of data via WISML and remote geosteering.

WPR interfaces with APS’ SureShot Directional plus Gamma (DG) MWD system, and uses industry-standard antenna spacings and dielectric corrections. The tool also offers industry-standard depths of investigation and vertical resolution. The complete SureShot plus WPR system operates to 175°C and is powered by batteries or batteries plus turbine alternator.

Varel launches High Energy series roller cone insert bits

Varel International announced the commercial launch of the High Energy series roller cone insert bits. This series was engineered as a solution to increasing demands on drill bits that require greater weight on bit and higher rotations per minute for faster drilling. The series features seal enhancements, improved seal/bearing system, and precision hydraulics and cleaning efficiencies. According to the company, initial field tests show a performance improvement of 25% in KRevs over previous technology.

LeTourneau offers build-it-yourself jackup kit

In response to high market demand for completed jackup rigs – often requiring more than a two-year lead time – LeTourneau Technologies Offshore Products now offers rig kit and license packages. This component packaging concept allows customers to build a LeTourneau jackup rig at a shipyard of their choice. The rig kits include such components as the company’s leg and guide components, jacking system, cantilever system, pedestal king post cranes, optional anchor winches, as well as detailed design drawings. Additionally, LeTourneau’s engineering support team will be available to guide customers through construction and to provide service through the life of the rig.

New WCS stuck pipe training available online

Well Control School has announced an online Stuck Pipe Prevention Training Program for derrick men, drillers, tool pushers and company representatives to aid in developing, implementing and utilizing a Stuck Pipe Program.

WellDynamics introduces HS internal control valve

WellDynamics, a Halliburton company, announced the availability of its HS interval control valve (HS-ICV), which is debris-tolerant and designed for high-pressure, deepwater environments characterized as severe operating conditions. The valve’s unique features include a proprietary metal-to-metal seal, allowing for the highest unloading capacity in the industry; a customizable flow trim; and optional position sensors to provide real-time confirmation of remotely actuated valve movements.

Handrails now standard on Liebherr crawler cranes for US

Liebherr Nenzing Crane Co is now fitting handrails as standard on top of crawler cranes delivered to US customers to reduce the risk of workers falling while climbing over the crane. Handrails were previously an option on Liebherr cranes, but with leading contractors increasingly demanding fall protection measures on their machinery, Liebherr opted to make handrails standard on all future orders from US customers.

L&M Radiator tests BOSS

L&M Radiator has released field and laboratory test results on its BOSS engine radiator (Brass Off Shore Service). The radiator was designed for offshore use and features brass finning brazed to brass tubes in a stainless steel framework. The radiator features a design common to all MESABI heat exchangers: individual cooling tubes held in headers with flexible rubber seals. The seals absorb shock and vibration, which can crack rigid soldered seams, and allow tubes that might be damaged to be replaced in the field and, often without removing the radiator from the equipment in which it is installed.

According to the L&M test report, the first BOSS radiator was put into service in June 2004 on an ocean-going nitro vaporizer used to cool a DC 60 Series engine. A month later, a second BOSS radiator was installed on an offshore rig with a Cat 3412C engine. Since those installations, 145 engine radiators, along with a few oil-to-air coolers, have been installed as of May 2008.

Most installations were on offshore rigs, and, according to L&M service and warranty records, to date, all have performed without failure attributable to galvanic action. In addition to those radiators installed, 18 units have been shipped to Singapore for use on ocean-going cementers. As of March 2008, four had been installed.

Formal lab tests on the BOSS from conceptual designs to development of a prototype took place from early 2003 to January 2004. Much of the testing tested the materials of a BOSS against the standard MESABI radiator tube, which uses a solder (lead-tin) composition to hold copper tube finning to both sides of flattened copper tubes.

When exposed to an accelerated salt air environment, the solder joint failed within a week as a result of galvanic action. An attempt to coat the copper finning and tubes with a variety of protective materials was not successful. Only brass finning brazed to brass tubes defeated galvanic action, which can be attributed to the similarity of materials used in the finning and tube components. Production BOSS cooling tubes have been tested for more than two years in a hot water, high-salt concentration bath with no evidence of deterioration of metal properties.

Oilfield calculations on Drillers.com

For drilling staff, calculations are part of their daily work. The average driller or toolpusher probably has available three choices when it comes to rig maths:

1. Calculator, together with formulae to use.
2. Generic software like Excel.
3. Specialist software, usually commercial.

There is now another way. With Internet access and a web browser, standard drilling calculations can be done using web-enabled Mathcad worksheets, which document all of the formulae and intermediate calculations. They are also optimised for small screens, such as the iPhone or other web-enabled PDA.

On www.drillers.com, you can see the Tonmiles worksheet, Audit version (Drilling Tools, Online Calcs).

In the figure at left, notice that the first data entry box is a pick list, which allows choices for the operation being calculated for. These include round or short trips, one-way trips, drilling with or without reaming, running casing or tubing. This applies a factor to the round-trip tonmile calculation.

The remaining data entries comprise boxes for entering numbers, but each box has to its right a pick list so that the unit entered can be chosen. Mudweight can be entered in one of six units, such as PPG, SG, kPa/m, psi/ft. Each data entry has a choice of units.

There are three main versions of the Tonmiles worksheet, all identical mathematically but formatted differently. The Work version hides all intermediate calculations, but the Audit version allows you to follow what’s going on.

Mathcad does internal calculations using metric figures. It also can work with units and enforce those units, so if a quantity of kilograms is entered and the user tries to subtract a quantity of metres, Mathcad doesn’t allow it. The results in each worksheet are always given in both Metric and Oilfield units.

As these worksheets reside on a web server, only the latest version can be seen, avoiding potential confusion with outdated versions.

Steve Devereux is CEO of Drillers.com and author of the Mathcad worksheets on the site.

By Mike Killalea, editor & publisher

Attitudes of DC readers toward anticipated oil prices have turned upside down in just six short months. A survey conducted on 1 April of subscribers to eNews from DrillingContractor.org, DC’s electronic newsletter, found that two-thirds of our discerning readers (66.2%) believed oil prices would exceed $100/bbl by 1 April 2009. More than one in three (34.6%) were even more optimistic, and responded that the price of oil would exceed $120/bbl.

Maybe those predictions will prevail. But for now, the views of DC readers have decidedly moderated, according to a 21 Oct reprise of the original eNews survey. Currently, only 2.5% of respondents look to $120-plus oil by next April. More than one in ten are quite pessimistic, bracing for oil below $60/bbl at that time. That compares with 1.2% in the April survey.

While exuberance has faded like a week-old rose, close to half (44.9%) still believe oil will range from $80-$100/bbl.

In the earlier survey, expectations stair-case upward, from very low to very high prices. Such was the temper of those times. At the 2008 Offshore Technology Conference, people swung to the wildly exuberant. Predictions overheard for 2009 OTC oil price ran to a starry-eyed $250/bbl.

This despite clear signs even then that $145-plus oil was not justified. Economic drivers had run oil $80 or so, and the ever-present terrorism and political instability premium edged prices up further. Similarly the odd Gulf of Mexico big blow. But the journey deep into 3-digit territory was financially driven: the US dollar cratered, and producers, seeking optimum return on petroleum, raised prices, not illogically. Further, currency investors and speculators, dismayed by the soft dollar, bought commodities – not just oil, but also gold, silver and the like – accelerating the frenzied price rise and buoying already dazzled expectations.

So today we face the inevitable reality check. In our more recent study, the range of predictions is decidedly bell shaped, albeit slightly weighted to the glum side of the bell. While the median response anticipates oil prices in the mid-range of $80-$100/bbl, about one in four looked for a $60-$80/bbl range – where we are today – and better than one in 10 feared prices could fall further. By contrast, one in eight expect $100-$120 oil.

PRESIDENTIAL HOPES

We were curious about our readers’ favorites in the US presidential race, so we ran a survey on this through eNews in late October. We wanted to see how opinions differed based on where a reader lives. By the time you read this, the election will be over. But if you are interested in the survey results, you can read them on www.DrillingContractor.org.

You can reach Mike Killalea at mike.killalea@iadc.org.

The days of $147 oil may not be gone forever, but don’t go looking for it to come around again anytime soon. Certainly not in 2009 anyway, analysts say.

With a financial crisis ripping through the global economy and oil demand down, the price of oil will likely “fiddle around below $100” in the coming year, one analyst said. Another commented on 1 October that crude could settle in the low-$70s by the end of 2008. In fact, as of 22 October, the price of oil had already plunged below $70.

Even more than the growing volatility of the oil price, however, they say the bigger concern is the natural gas market. An overabundance of supply has put a considerable damper on prices – from $14 down to under $7 in recent months. That softness will likely carry through into 2009, with potentially significant impacts on the North American rig count.

The world economy

As of October, the economic crisis and its effects were still unraveling. The US Congress had passed a $700 billion bailout plan. World leaders appeared ready to take aggressive measures to help the economy as well, with an international economic crisis summit planned for 15 November. How this all will play out is still far from certain. How it might impact the oil and gas industry is another question mark.

“It’s a little early to say, but it’s going to make capital harder to get for E&P companies and affect their activities,” said Marshall Adkins, managing director for Raymond James & Associates. “That’s mainly the smaller companies. The larger companies have huge free cash flow. But independents and anyone with any amount of debt is going to have issues.”

And because there are consolidations anytime there’s a downturn, this slow economy could become prime grounds for cash-rich companies with strong order books to buy up small guys overextended on debts, said Eugene Murphy, investment principal for Kenda Capital.

There is a silver lining for this industry, however. If anybody is going to get a loan in this economy, it will probably be us, said George Littell, partner at Groppe Long & Littell. “I think (the downturn) points to the fact that the oil and gas industry is a lucrative one. We’re the companies with the real assets. When they’re sorting out who gets credit, oil and gas companies are at the top of the list.”

Rather than the oil price or the credit crunch, the real snag that the industry is about to hit is with natural gas, Mr Littell emphasized.

“I think the more material problem for rig contractors is that the industry has become a victim of its own success,” Mr Littell said, explaining that contractors and rigs are actually drilling so efficiently, they oversupplied the market.

The industry is getting too good at getting natural gas out of the ground, especially with the shale plays, he said. Drilling long horizontals with multiple stages of fracturing has turned out to work quite well on most of the shales. Not only that, but the industry is also “trying to drill (the shales) all at the same time. You’d think you’d develop the most economic ones first, then move on to the next in order of size and complexity. That’s not what the industry is doing,” Mr Littell said.

Another factor that could make a significant difference is the number of LNG plants coming online in late 2008 and early 2009. These plants, located all over the world, were originally supposed to be more spaced out when construction began three or four years ago, Mr Littell said, but delays and other glitches have pushed them all together to start within a short time span.

“All in all, (the LNG plants will bring on) about a million and a half barrels a day of oil equivalent. We’ve gone nearly a year with essentially no increments to LNG supply, and, in the next six months, there’s going to be a bunch of it,” he said.

In fact, these supplies don’t even have to get shipped to the US in order to have an effect here – they already are more likely to get sent to Europe and Asia rather than to the oversupplied US market. Simply having access to additional LNG “will put pressure on the domestic gas market,” Mr Murphy pointed out.

So with too much shale gas and global LNG, how low can we see natural gas prices go in 2009? “We’re at $6.75 next year, which means you’ll probably go below that for periods of time,” said Mr Adkins.

Mr Littell was less optimistic, commenting, “There is too much gas built up. If we get something close to normal weather this winter, there will be a good shake-out of natural gas prices. … You can see it test $5, probably around February.” He also forecast a decline in the North American rig count in the 10% to 20% range.

Mr Murphy declined to provide a forecast on natural gas prices but noted that the number of wells drilled could drop by anywhere in the 5% to 30% range, depending on whom you ask. “There are lots of projections out there, anything from a flat market to the latest numbers out of Canada suggesting (drilling activity in Canada will drop) from 17,500 in 2008 to 16,500 next year. It’s all over the place.”

Shrinking budgets

Although the winter season usually does bring more bite to natural gas prices, at least somewhat, the upcoming winter could be too late to help the 2009 market because companies are already putting together CAPEX budgets for next year. “People are already looking through to the end of 2009 … if they think the market is going to soften next year, they’ll start to cut back on their CAPEX plans,” Mr Murphy said.

Indeed, news have been steadily trickling out, especially from smaller and independent operators, announcing reductions in 2009 budgets. For example, SandRidge Energy, an Oklahoma-based E&P company focused on West Texas resources, announced on 2 October that it’s reducing its ’09 budget from $2 billion to $1 billion. The reduction “is a direct response to recent declines in natural gas prices,” the company said in its announcement.

Petrohawk Energy, which focuses on ArkLaTex, Oklahoma and the Permian Basin, announced a similar budget cut the day before, from $1.5 billion to $1 billion. The reallocation of capital reflects an increased emphasis on development of non-proved locations in the Haynesville and Fayetteville shales, the company said.

Even large independents haven’t been immune. Chesapeake Energy announced in late September it is reducing its CAPEX budget for the second half of 2008 through the end of 2010 by approximately $3.2 billion, or 17%, in response to the approximate 50% decrease in natural gas prices since June 2008 and surplus concerns. The company also plans to reduce its current operated rig count of 157 to approximately 140 by the end of 2008 and to keep that number flat through 2009 and 2010.

In addition, Chesapeake has shut down approximately 100 million cu ft/day of net natural gas production, citing “unusually weak wellhead natural gas prices that are substantially below industry break-even costs.” This represents approximately 4% of the company’s current net natural gas and oil production of over 2.3 billion cu ft/day of natural gas equivalent.

Volatile oil

Amid discussions about lower natural gas prices, it’s also important not to overlook the price of oil. That picture has become much more volatile in recent weeks and months. From a record high in July 2008 of $147/bbl, it dipped below $70/bbl by late October – that’s about a 50% drop over about a three- to four-month period. On 23 October, in fact, oil closed at just above $64/bbl.

How serious is this price drop? It seems like $65 or $70 oil is nothing to cry to over. If you think back to the ’90s, many operators would’ve been thrilled with even $50 oil. Yet, everything is relative. Now that the world knows $147 oil is possible, have our expectations changed?

OPEC is certainly worried. The group first called for an emergency meeting in Vienna on 18 November, then decided the situation was too pressing and moved the meeting up to 24 October. The result was a 1.5 million bbl/day cut in production, effective 1 November. “Oil prices have witnessed a noticeable collapse … unprecedented in speed and magnitude … which may put at jeopardy many existing oil projects and lead to the cancellation or delay of others,” according to a statement released after the meeting. They also noted the financial crisis and its “noticeable impact on the world economy.”

Certainly, consumer demand for oil has been falling and continues to drop. On 10 October, the International Energy Agency (IEA) slashed its 2009 oil demand forecast by 440,000 bbl/day. World oil demand is expected to average 86.5 million bbl/day next year, according to the report.

“(The demand drop) is a response to $145 crude and $4 gasoline. That’s exactly what had to happen,” Mr Adkins said.

“People are cutting back wherever they can,” added Mr Murphy, noting that one X factor to demand could be Americans’ driving habits. “If Americans would just wean themselves off pickup trucks, they wouldn’t need quite as much as they consume.”

Mr Littell agreed, pointing to the fact that consumer sentiment is already pushing US automakers away from gas guzzlers. “The market is all small vehicles and hybrids now. You can’t sell big cars. If they continue that for a long period of time, it starts making a substantial difference (in oil demand).”

Where is oil price headed?

It’s unlikely that crude prices will return above the $100 mark anytime soon, the analysts agree. “Next year, we’ll probably fiddle around below $100. How low it’s going to go, I have no idea,” said Mr Murphy, but he pointed out that “this is a short-term glitch. We’re still not keeping up with supply and demand in the long term.”

Even so, $147 oil was definitely an abnormality, Mr Murphy acknowledged, citing the weakness of the US dollar as one factor.

Mr Littell agreed it was an atypical event and said he believes the entire thing was an unplanned blunder. The IEA had forecast an increase in non-OPEC production in 2007, leading OPEC countries to cut back on their output, he recounted. But the forecast increase never happened, and OPEC didn’t begin increasing production again until late 2007. “Oil demand was up in 2007 but production was down. It wasn’t designed, it was just a mistake that took them a while to correct,” he said.

Mr Littell said he believes oil could stay in the low-$70s in 2009. And if you think that sounds like it’s on the low side, try to put it in line with your pre-$147-oil expectations. “Stop and think about it for a minute: What was the oil price when 2008 began? Low-$70s,” he said. “We just had a wild ride.”

$70 oil is by no means bleak, and Mr Littell believes this is still a great time to be in the business. “I don’t think we’re going to see $147 oil again anytime soon, but $70s will do just nicely. And if operators can make good money at those prices, I think contractors ought to, too.”

Most of the world’s offshore E&P regions are expected to remain strong or see increases in rig demand, particularly for deepwater and ultra-deepwater activity. ODS-Petrodata’s 2009 forecast indicates more demand than available floaters. For jackups, however, there may be more supply than demand most of the year.

ENSCO International is only one of several major offshore drilling contractors bullish on the deepwater market, and has ordered deepwater rigs along with others such as Transocean, Noble Corp and Pride International.

“We’re very bullish on deepwater, and our seven-rig ENSCO 8500 Series semisubmersible newbuild program is solid evidence of our commitment to the industry,” said Mike Roth, ENSCO director, deepwater marketing & contracts. The company ordered three new deepwater semisubmersibles, all on speculation, in addition to the prior four units that are already contracted.

“We firmly believe that the (deepwater) market is robust and we will secure contracts on those rigs in a timely basis at acceptable market rates,” Mr Roth said. “Our strategy is to continue to grow in the deepwater arena.

“A number of independent operators are moving into (deepwater), primarily in the Gulf of Mexico,” he continued, “companies such as Nexen, Noble Energy, Cobalt and others. They have the capacity and the acreage to drill in deepwater and are valuable clients using our rigs.”

Mr Roth sees a growing demand for deepwater rigs worldwide, including the US Gulf of Mexico, Mexico, Brazil and West Africa, as well as in the Mediterranean and Australia, with Indonesia and India also experiencing demand growth. “Drilling development wells on the back of the significant deepwater discoveries worldwide will be an essential component of deepwater rig demand,” he explained.

Tight credit market

The credit market crunch that began in September could play an important role in different regions and business segments. Some companies will fare better than others, depending on the types of operators in those regions. However, nearly all are expected to see some effect. The oil price has already fallen along with stock exchanges.

A report in early October by Raymond James & Associates sounded a warning. “The global financial market melt-down … should drive energy demand lower, drive energy prices lower, depress M&A activity, delay energy infrastructure build-out, and reduce oil and gas drilling activity.”

The report also said that several companies building offshore rigs on speculation tapped the previously easy credit market, but new announcements of speculative rigs will become scarce.

Additionally, in light of lower natural gas prices, many E&P companies have had difficulty maintaining their spending levels.

“I don’t think (the financial crisis) will have a significant impact with the major international oil companies,” Mr Roth said. “Certainly the industry will have to monitor the worldwide economy, which will have an impact on the demand for oil and natural gas, but we don’t necessarily see any immediate effect.”

Large offshore contract drilling companies usually finance rig newbuilds from cash flow. That’s the case with Pride, which has four drillships under construction. Transocean, Diamond Offshore, Noble and others are likely in the same situation. Noble, in fact, recently ordered a new drillship at a cost of $585 million, a bargain in today’s newbuild market.

The credit market could be a boon to the large offshore drillers, assuming some of the rigs built on speculation become distressed merchandise. “I think the impact of tight credit potentially is very serious for contractors who have ordered rigs subject to financing,” explained Kevin Robert, Pride senior vice president, marketing and business development.

“A lot of speculators who have ordered rigs and who have put minimal money down will have a large payment to make later, and they will need to have a contract in order to finance a portion of that rig.”

Pride is investigating additional newbuilds and has an option for another drillship, but there is plenty of time to exercise that option, Mr Robert said. Meantime, the company is looking at another potential avenue to expand its fleet. “We are looking at other rigs that have been ordered to understand their situation,” he said. “Maybe there is an opportunity that comes up.

“We want to invest more in the deepwater market,” he added. “How we do that, depends.”

Hercules Offshore, which grew its fleet from five rigs a few years ago to 35 jackups and three submersibles today via a series of acquisitions, continues to look for acquisition opportunities. However, “it’s not a time to stretch your balance sheet,” said Hercules CEO and president John Rynd. “Those opportunities will be there, and we will continue to look and evaluate (acquisition opportunities), but we are taking a more cautious view.”

For small independent operators who have to drill a well with financing, it might be difficult to promote that project presently. The good thing is that the prospect doesn’t disappear because financing is unavailable; it (usually) gets postponed. Some larger independents also rely on credit markets, however, they also have base programs with which they can continue.

“At the moment, it is still too soon to predict to what extent current events will affect overall activity in 2009, but we anticipate a slowing in the rate of increase of customer spending,” Schlumberger chairman and CEO Andrew Gould commented in announcing the company’s third-quarter results in mid-October. He added that he anticipates effects of the credit market crunch to be limited to North America and some emerging exploration markets overseas.

US Gulf of Mexico

Dayrates for jackups in the US Gulf rose considerably during the first nine months of the year but leveled going into the fourth quarter. Still, the shelf market appears solid. “One of the drivers has been the continued migration of jackups out of the Gulf to international markets,” Mr Rynd said.

Mr Robert agreed: “The jackup market in the Gulf of Mexico is very strong right now due to the supply side being so tight.”

One doesn’t have to look back too far when there were 150 jackups in the Gulf, Mr Robert noted. Today, the figure is closer to half that, with around 60 of those rigs being marketed. With as many as another half-dozen expected to leave in 2009, plus three jackups that were lost during Hurricane Ike, the number of marketed units could soon drop to around 50, perhaps lower. As a result, drilling contractors expect the shelf market to remain buoyant.

Dayrates for 250-ft mat-supported jackups ranged from around $58,000-$63,000 in January 2008 but increased to $75,000-$95,000 during the summer. For 300-ft independent-leg cantilever jackups, dayrates ranged from about $115,000-$120,000. These increases were due to the tighter market plus higher natural gas prices during the summer.

Natural gas prices fell during the late third quarter and early fourth quarter, which could impact jackup demand as smaller independents pull back on exploration activity. Combined with the tight credit market, a pullback of activity could adversely affect the shelf market.

There is no such worry in the deepwater market, where rigs are enjoying virtually 100% utilization along with dayrates in some cases approaching $600,000. The lack of equipment is responsible for those rates, of course, but as far as exploration and development work, there is no end in sight for deepwater rigs.

Of the 99 semisubmersibles and drillships under construction with deliveries stretching to 2011, only 29 presently are available for contract. During 2009 alone, 25 semisubmersibles and drillships are scheduled for delivery, all with contracts and many destined for the US Gulf.

Mexico

The US Gulf and the Mexican Gulf continually feed off of each other for rigs, both jackups and deepwater units. In fact, several rigs departing US waters are expected to head to Mexico. Additionally, Pemex continues to tender for jackups internationally to fulfill their requirements. Earlier this year, Pemex had rig tenders calling for three independent-leg jackups, another for three more jackups. They’re expected to issue a third tender for another three jackups by the end of the year.

The US Gulf has been a primary source for Pemex’s jackups, but the company may have to begin looking in other areas as most of the rigs they are tendering are independent-leg units. Previously, Pemex chartered a mix of independent-leg and mat-supported jackups; however, their current and future requirements specify the former due to their flexibility for the company’s drilling programs.

Switching from mat-supported rigs would previously have been of concern to drilling contractors like Pride, which has seven mat-supported rigs contracted to Pemex. However, as mentioned earlier, rigs leaving the US Gulf has only further tightened the market there. Many of Pemex’s requirements could still come from the US, and that could be good news for jackup contractors.

“If Pemex increases its demand for independent-leg jackups, they will be taking them from the US,” Mr Robert explained. “The rigs that they will take, the 250-ft independent-leg cantilevers, drill the same wells as our 250-ft mat rigs, increasing demand for mat rigs up north.”

Pride has seven mat-supported rigs and two independent-leg jackups in Mexico. The two independent-leg units are contracted to Pemex through August and September 2009, while all but one of the mat-supported units had contracts that expire during fourth quarter 2008. Hercules has two mat-supported rigs with contracts that expire in mid-2009.

As far as rigs outside the US Gulf, Pemex contracted the Noble Carl Norberg, a 250-ft independent-leg jackup, from West Africa. This will give Noble 11 jackups in Mexico. The dayrate is about $155,000 for two years, compared with about $170,000 in West Africa, although the rig did not have a term contract in Africa. However, the dayrate is tied to an index that calls for re-pricing every 90 days based on an index of jackup rates in seven international regions, according to Noble. Most of Pemex’s jackup contracts are tied to various pricing indexes.

Pemex is operating five semisubmersibles, but four of them are considered mid-water depth units rated to drill in about 1,500 ft to 3,000 ft. Only one rig, the 7,000-ft Noble Max Smith, is considered deepwater.
“Pemex would like to contract another deepwater rig in 2009,” Mr Robert noted, “but I don’t think they are going to be successful because there are no rigs available.”

The first opportunity for Pemex to bring in a deepwater rig is when SeaDragon Offshore’s Oban B is delivered in late 2009. The rig is rated for 10,000 ft of water and will work for Pemex under a five-year contract.

The next deepwater newbuild semisubmersible for Pemex won’t be delivered until the second half of 2010, Grupo R’s 7,500-ft La Muralla III, also contracted for five years. A third, PetroRig III, will begin working for Pemex in early 2010. This rig is rated for 10,000 ft of water.

Petrobras

“Petrobras has the geology like nobody else in the world,” Mr Robert emphasized, “and they can afford and have demonstrated a very long-term view of the drilling market.”

Petrobras has been recognized as one of the world’s deepwater E&P leaders for years. The company has developed numerous technologies and innovations that have become standard in nearly every deepwater basin, such as subsea technology, FPSO and floating production systems. However, for the most part, the company has drilled and developed fields in around 5,000 ft of water or less. Even today, Petrobras’ drilling activity is generally in less than 5,000 ft of water.

That’s going to change in the near future, though, aided by better seismic technology that enables Petrobras to “see” through subsalt prospects and more accurately locate wells in greater water depths. As a result of the anticipated growth in ultra-deepwater, Petrobras is working to essentially double its number of floating rigs.

Early in the fourth quarter 2008, Petrobras was contracting or operating 29 semisubmersibles and six drillships, the majority of which are rated to drill in 3,000 ft to 5,000 ft of water. However, most of them were drilling in water depths substantially below their rated capacity. Looking forward, assuming Petrobras continues to contract these rigs, it will have under contract another 17 semisubmersibles and 11 drillships by the end of 2012, essentially doubling its fleet of deepwater and ultra-deepwater rigs. Several of these rigs are rated to drill in up to 10,000 ft of water.

With the Brazilian government pushing for more local content, Petrobras has awarded contracts for about 15 newbuild semis and drillships to Brazilian drilling contractors. Several are under construction, but several more are listed as “on order” by ODS-Petrodata, including a few without a specific shipyard. “Many of those contractors are very short on infrastructure,” Mr Robert noted, “and they are affected by the high cost of newbuilds as well as the current credit crunch. A number of them signed contracts without shipyard slots subject to financing.

“I think another part of the story is how many of those rigs that Petrobras has ordered from local companies will actually be delivered.”

Additionally, some expect Petrobras to produce additional rig tenders that could include a total of perhaps two dozen more deepwater and ultra-deepwater rigs. The government wants to increase local content by having most or all of those potential newbuild rigs constructed in Brazil. The problem is the lack of local shipyard capacity.

“Petrobras understands the risk of trying to build rigs in Brazil,” Mr Robert said. “But no matter what the outcome, their increasing demand (for offshore rigs) will impact our business for the next 20 years.”

Dayrates for mid-water depth semisubmersibles in Brazil generally range from the high $200s to the mid-$300s. A couple of Noble’s semisubmersibles in Brazil are working for substantially less but have new contracts that call for significantly higher dayrates. For example, the Noble Paul Wolff, rated to drill in 9,200 ft of water, is contracted to Petrobras until November 2009 at a rate of about $164,000/day (this contract was signed in 2005). The rate will increase to $428,000 under a new five-year Petrobras contract until November 2014.

Pride’s semisubmersibles, rated for up to 5,700 ft of water, are contracted to Petrobras with dayrates ranging from the low $200s to the low $300s. The Sea Explorer, a 1,000-ft water depth semisubmersible, will begin work for OGX in Brazil in August 2009 at $335,000/day following its contract with Eni in the Congo at $255,000, which is closer to $270,000/day with a bonus, according to Mr Robert.

West Africa

The West African jackup market softened somewhat late in 2008 with several idle jackups hanging over the market. Contracts for as many as four additional jackups expire before year end 2008, with contracts for another half-dozen jackups set to expire during the first half of 2009.

Hercules operates two jackups in West Africa at dayrates of around $150,000 each. Mr Rynd believes the slack demand is due primarily to the large amounts of money being spent in deepwater, primarily offshore Angola.

“Over the last four years, jackup demand has grown by only about three rigs,” he said. “With a large continental shelf and oil prices through the roof, you think there would have been higher demand.

“Having said that, I think longer term (West Africa) is going to be a very good market.”

Mr Rynd said his company has the largest lift boat fleet in West Africa, with 18 in Nigeria, and believes its jackup presence can grow with the lift boat infrastructure. “We have a good beachhead on which to grow, and we will have a significant West African presence for a while.”

He expects the jackup market will see an uptick beginning in the fourth quarter 2009 because of lease transfers to different companies. “We are getting a market sense that people are starting to look for jackups, in Angola and Nigeria specifically,” he said. West Africa is also a possible home for Hercules 350, a 350-ft independent-leg cantilever jackup in the US Gulf.

The company’s West Africa rigs include the Hercules 185, contracted until September 2010 at about $150,000/day, and the Hercules 156, contracted to ADDAX until February 2009 at the same rate. The latter rig will undergo shipyard work at the end of 2008, including adding a leg to bring it up to its design capacity of 150 ft. ADDAX is reportedly seeking a 350-ft jackup to begin work in early 2009.

Like Mr Rynd’s outlook for the jackup market, Mr Robert believes West Africa’s floater market will grow from a demand standpoint. “The industry will put more rigs into West Africa,” he said. “The question is whether (the industry) is able to do that right now. Everything is contracted, so if I was to move another rig into West Africa, I’m not sure where to find it other than build a new rig.”

One of Pride’s newbuild drillships is contracted to Petrobras for work offshore Angola, with delivery in 2011. Another is available for contract with a delivery date in the fourth quarter 2011. “That rig could potentially go anywhere in the Atlantic Basin or the Far East,” Mr Robert explained, “but my bet would be more inclined toward the Atlantic Basin.”

Middle East

ODS-Petrodata is projecting average jackup demand in the Middle East to increase from 89 in 2008 to 112 in 2009, beginning during the second half of the year. In the meantime, it is predicting a shortfall in supply during most of 2009 beginning late in the first quarter.

“The Middle East is the world’s largest jackup market,” said Mr Rynd, “and it looks like it’s poised to continue its growth. Saudi Aramco is evaluating bids for three to five jackups.”

Mr Robert agrees: “Saudi Arabia is a very strong growth market. The net increase in demand over the next couple of years is probably close to 30 jackups.”

Mr Rynd also noted that there could be additional tenders from Saudi Aramco soon. Maersk Oil & Gas has issued tenders for jackups to work offshore Qatar as well.

Hercules has three jackups in the region, one contracted to Occidental in Qatar until July 2009 at just over $100,000/day. Two others are contracted to Saudi Aramco until September 2011 at rates from the high $120s to the high $130s. These rigs are used in Saudi Aramco’s oil plays, Mr Rynd said, but the push for the past year or longer has been to drill deep, HPHT gas wells that require larger jackups.

However, according to Mr Robert, many operators, especially in the Middle East and Southeast Asia, realized that they could play the presence of newbuild jackups in shipyards in Southeast Asia to try to keep dayrates low. Operators also are offering shorter-term contracts – two years or less – in order to have more rigs re-contracting.

“It’s still a seller’s market, but operators with work (in the Middle East) are mostly national oil companies,” Mr Robert explained, “so they can afford to wait to contract a rig if they think the rates will go down.”

Southeast Asia

The Southeast Asian jackup market is expected to rise from an average of 39 contracted jackups during 2008 to an average of 45 in 2009. Despite this demand increase, ODS-Petrodata forecasts show the Southeast Asia jackup market may have a surplus of about six jackups during the remainder of 2008 and more than double that figure during 2009.

The reason is lower demand during the second half of 2009, an average of 41-43, down from 49 in January 2009 and remaining at that level during the first half. Meantime, supply is expected to increase from around 53 jackups in January and rising steadily throughout 2009, ending the year with an expected supply of 64-66 jackups.

Despite this outlook, Mr Rynd believes the Southeast Asian jackup market is still fundamentally solid. While Hercules currently has only one jackup in the region, Hercules 208 offshore Malaysia working for Murphy, Mr Rynd said the company wants to grow in the region. Hercules 208 mobilized from Trinidad, where it was cold stacked, and was upgraded “from the drilling systems to the quarters. This opportunity with Murphy may lead us to further opportunities.”

Like most other regions with floating rig requirements, Southeast Asia is expected to experience more demand for semisubmersibles than supply. While there are a couple of standard water-depth semisubmersibles available early in the fourth quarter, ODS-Petrodata is forecasting a deficit of such equipment during most of 2009 beginning in March. The deficit could be as high as four or five rigs on average throughout 2009.

Among the tantalizing offshore provinces are surely the Mediterranean, Black Sea and Caspian. What is the real petroleum potential? Has it been talked up too much or will patience and persistence eventually pay off for this sprawling region linking Europe with Africa, the Near East and Asia?

Of the three, the land-locked Caspian is the most talked up and clearly the most productive; moreover, it is where the modern oil industry began.

In the Mediterranean, Egypt is leading the way, though Libya is intent on making up for lost time, while others like Italy and Montenegro still struggle.

In the Black Sea, Bulgaria and Turkey informally vie for the top slot while others struggle to get anywhere.

In geopolitical terms, all of these regions offer challenges. But it’s especially so in the Caspian, given the still unresolved all-inclusive parceling of this important aquatory between its littoral states, though various sub-agreements are in place. The potential for conflict particularly exists in the Eastern Mediterranean, bearing in mind that uneasy neighbours Egypt and Israel are both active offshore.

That the current mobile drilling unit population for the Mediterranean and Black Sea is just 26 units tells its own story. They comprise mostly jackups, with a further six or so MODUs due into the region, according to the Stewart Group’s tracking service.

Stewart’s October 2008 listings include nine offshore Egypt and five units working in Libyan waters, plus two each offshore Romania and Ukraine.

As for the Caspian, the limited population of rigs has been growing slowly by dint of limited rebuilds, plus the Maersk Explorer semisubmersible, Transocean’s Trident 20 jackup and the Iran Alborz semi that is currently commissioning. Maersk Explorer is a Lider-type rig whilst the Trident-20 would be at home in the North Sea.

In terms of which petroleum companies are active in this trio of sub-regions, it really is a mixed bag. Independents like Lundin Petroleum and Melrose Resources are prominent; a notable mid-ranker is BG Group, while BP and Eni tend to have the highest public profile among the majors.

A number of minnows are also attempting to carve niches for themselves, of which Petroceltic is one example. However, such companies are at greatest risk in the current global financial turmoil and some may not survive, or be forced into shotgun marriages through the lack of money.

To quote Richard Griffith, director of equity research at Evolution Securities: “Right now, if you are a pure exploration play in need of cash, then you have no hope. You are in dire straits. It will be like a forest fire, with only the stronger trees left standing in a few months time.”

If that turns out to be the case, then the drilling scene for the Mediterranean will simplify somewhat – and rapidly.

There has been at least one notable exit, namely ExxonMobil’s decision to shut down its Azerbaijan office in 2006 following a number of high-profile failures, including the Zafar-Mashal and Nakhchivan oilfields.

On the other hand, ExxonMobil is back in Libya big time, having secured a number of promising offshore concessions, which is the cue for taking a peek at what appears to be happening in the aquatory of this key North African energy player.

LIBYA

The political and social changes over the last decade or so have clearly had a positive impact on investment, and when sanctions by the UN were suspended in 1999, many foreign companies returned to the country, with large tracts of acreage made available for exploration. Initially they were onshore, but increasing attention has been paid by the Libyan National Oil Corp (NOC) to encourage exploration offshore.

The offshore push is helped by the fact that the Sirte Basin extends into the Gulf of Sirte. There is also the Gulf of Gabes, where oil has been found in shallow waters. Here Eni is producing the El Bouri field, currently the largest oilfield in the Mediterranean, though it peaked at 110,000 bbl/day in 1997.

It is perhaps also useful to note that, in 1988, Libya and Tunisia settled a long-standing territorial dispute over an area on the Libya/Tunisia border in the northern part of the Gulf of Gabes, also known as the November Seventh concession. The area is estimated to contain 3.7 billion bbl of oil and some 12 trillion cu ft of gas. The neighbouring states then agreed to exploit the area through the 50:50 joint venture Libyan-

Tunisian Joint Oil Company.

It is clear, however, that NOC is now heavily dependent on foreign companies for exploration, project funding and new-generation technologies, especially for extended oil recovery.

So what is the offshore future for Libya?

Basically, the emphasis is on assuring output from current assets such as Bouri and Al Jurf, pending the outcome of initial exploration of acreage awarded under the EPSA IV (E&P sharing agreement) program. There have been four rounds under Libya’s EPSA IV program, each of which has had an offshore element.

Round 1 offered 57 blocks, Round 2 offered 44, Round 3 offered 41 and Round 4 offered 41. All had an offshore content; for example, Round 4 offered 22 such blocks. Only four companies out of 13 applicants were awarded in that round – Shell, Gazprom, Polski and Sonatrach.

This is in sharp contrast to Round 3, which attracted 70 applications, of which 47 were chosen to bid for the 12 offshore and 29 onshore blocks.

Companies that have secured offshore positions range from BP, ExxonMobil, BG and StatoilHydro, to various Chinese, Indian and Japanese companies, plus Gazprom, which was the only company to secure offshore
acreage in Round 3, in return for a $10 million signature bonus.

BP, a traditional pre-sanctions player in Libya, was not initially lucky under EPSA IV, though shuttle diplomacy between the UK and Libya later helped land the UK group a huge offshore prize in 2007, though this was not ratified until early 2008.

The essence of the $900 million BP bilateral agreement is that the company will drill 17 exploration wells in an onshore area in the Ghadames Basin – this is an area larger than the whole of Kuwait – and in the offshore sector of the Sirte Basin, an area equivalent to the size of Belgium – some 54,000 sq km.

BP has also committed to about 20 appraisal wells and to acquiring 30,000 sq km of 3D and 5,500 km of 2D seismic data over the Ghadames and Ghadames South acreage and the Sirte offshore acreage. The first seismic contract has been awarded.

ExxonMobil has built a sizable holding over the various rounds.

Most recently, in November 2007, the company secured an exploration and production sharing agreement for Block 21, offshore Sirte Basin. The initial agreement runs for five years and covers exploration in water depths to 2,000 m.

Like BP, ExxonMobil committed to a signature bonus, as well as to a training program for Libyan professionals, in addition to its previously agreed funding of educational facilities in Libya.
In February 2007, ExxonMobil secured E&P sharing licences covering four blocks in Contract Area 20, offshore Sirte Basin in water depths to 2,000 m.

ExxonMobil is also in the very early stages of an exploration program on Contract Area 44 of the offshore Cyrenaica Basin, which was awarded to the company in Round 2 in 2005. To date, the supermajor has completed an environmental impact assessment, met with local stakeholders, and is conducting a 2D seismic acquisition campaign.

Neither BP nor ExxonMobil have got to the stage of having MODUs on hire.

EGYPT

With nine MODUs on contract and the jackup JP Bussell scheduled to arrive and go to work for Shell, offshore Egypt is buzzing with activity, primarily development-related, though exploration continues to generate results.

The most prolific area remains the West Delta Deep Marine (WDDM) concession, operated by BG in partnership with Petronas and EGPC, collectively working as the Burullus Gas Consortium.

They have made nine gas discoveries on the concession: Scarab, Saffron, Simian, Sienna, Sapphire, Serpent, Saurus, Sequoia and Solar. It has been suggested that the recoverable reserves on West Delta total 14 trillion cu ft of natural gas.

WDDM is being developed in phases. Phase 1 covered the Scarab and Saffron fields; Phase 2 Simian and Sienna; Phase 3 Sapphire; and Phase 4 Scarab, Saffron and Simian. The other fields will be developed as gas production from these existing fields decline. Other current developments include: Denise (BP, operator), Taurt (BP) and Asad/Zaref.

There are likely to be some major developments in the period to 2012. In particular, BP and its partners have made large discoveries on the North Alexandria A and North El Burg concessions. The largest appears to be Raven, with reports of up to 7 trillion cu ft recoverable reserves. Others include Giza and Satis.

That Egypt holds an allure is demonstrated by the fact that Amerada Hess and partners recently offered a signature bonus of over $1 billion for the area, including the Abu Sir fields.

While the pace of discovery appears to have slowed, this may have more to do with the need for Burullus and others to develop what they have found to date, rather than a decline in prospectivity, witness the latest find by Gaz de France in 50-50 partnership with Dana Petroleum of Aberdeen early in 2008.

The exploration well WEB-1X was drilled on the West El Burullus concession and, according to Dana, the area also contains numerous additional prospects at both shallow and deeper horizons.

WEB-1X was drilled in just 19 m of water by the jackup Ocean Spur to a total vertical depth of 2,403 m (7,884 ft), targeting a Pliocene prospect consisting of a turbidite sandstone channel system.

According to Dana, the well encountered good quality gas-bearing sands and, during a multi-flow rate drillstem test, flows of up to 27 million cu ft/day were achieved. WEB-1X has been suspended for potential re-entry and future use as a producer.

Dana CEO Tom Cross was ****-a-hoop when the results were disclosed early February. He said at the time: “The WEB-1X flow test results are very encouraging. Making a discovery with our first well highlights the outstanding exploration potential of West El Burullus and significantly increases the likelihood of success for additional prospects which are being identified.”

While not strictly within the remit of this review, it is important to point out that Egypt’s original offshore province, the Red Sea, is still generating new finds. In April, it emerged that BP had made a significant oil discovery on the Northern Shedwan Block. Egypt Kuwait Holding, a partner in Tri Ocean Energy, BP’s partner in the concession, reported that the new find has been tested to indicate it is capable of producing some 10,000 bbl/day of oil.

BP was awarded a nine-year license for the concession in 2004, for which it pledged to invest a minimum of $20 million in E&P activities, including the drilling of at least four exploration wells.

Rigs currently noted as working the BP account in Egyptian waters are the jackup GSF Constellation II and the semisubmersible Pride North America.

ISRAEL

The emergence of Israel as an offshore player in the Mediterranean merits inclusion in this whistle-stop tour.

Until drilling started in the late 1990s, Israel had no confirmed offshore oil and gas resources. But three gas discoveries – Mari, Noa and Or – changed that and pointed to proven offshore gas reserves of at least 3.5 trillion cu ft – not large on the grand scale of things, but a start, especially given that Israel’s Petroleum Commission believes that a proportion of the state’s estimated 5 billion bbl of oil reserves could lie beneath the offshore gas resources.

The now developed Mari and Noa (1.5 trillion cu ft combined reserves) are the largest gas discoveries to date. They were located by the Yam Tethys Joint Venture comprising Samedan Mediterranean, Avner Oil Limited Partnership, Delek Drilling Ltd Partnership and Delek.

The dominant player offshore Israel has unquestionably been BG, though their relationship has been a rocky one. A few years back there were threats and counter-threats regarding Matan/Michal, despite the promising 2.4 trillion cu ft potential of the Tamar target for which the estimated exploration cost was touted as being some $40 million in 2003 money. BG (25% interest) had tried to find an investor to purchase 39% of the drilling rights, but failed after an extensive sweep of the market.

Today, Israel has just the Mari-B and its Noa satellite in production, and BG is pulling out altogether and focusing on the Gaza Marine discovery offshore neighbouring Palestine instead.

That 1 trillion cu ft discovery was proven in 2001, since when the company has struggled to get it developed. The idea had been to sell the gas to Israel, but negotiations collapsed at the end of 2007. A concrete outcome was pending at the time of writing, with rumours circulating that a deal may yet be clinched with Israel Electric Corp.

Meanwhile, although BG has given up on offshore Israel, Noble Energy is pressing ahead with plans to drill the Tamar 1 wildcat in the Matan (309) Block during Q4 2008 using the semisubmersible Atwood Hunter.

The company is also bringing in the new drillship Aban Abraham.

According to IHS, the drilling of this well was originally proposed in 2003 when costs were estimated at up to $40 million versus some $145 million today. It says the Tamar structure may hold recoverable reserves of some 2.6 trillion cu ft of gas, rather more than the original BG estimate.

Noble became an offshore Israel player by securing a 33% interest in and operatorship of the 318 sq km Matan deepwater block in July 2006.

BLACK SEA

Shifting to the Black Sea, the programs that are perhaps attracting the most attention and delivering results are offshore Bulgaria, which is largely the preserve of UK company Melrose Resources and the Turkish sector, where significant progress appears to have been made over the past couple of years by Toreador Resources.

First, Bulgaria, where Melrose continued to make cautious progress with its offshore concessions, reporting in January 2008 that it had made a shallow-water gas field discovery on Galata Block.

The Galata-E3, Kaliakra probe was drilled using the Atwood Southern Cross and tested an analogue of the nearby Galata gas field, with the main reservoir target in a Palaeocene-aged formation. In essence, open-hole log data pointed to a 10-m (33-ft) net pay interval with an average porosity of 31% and high gas saturations. Due to the high quality of the reservoir, flow-testing was not required, and Melrose suspended the well as a future producer.

Indeed, further drilling started early October with Melrose taking on hire the rig Prometeu.

Melrose financial director Munro Sutherland explained that the Kavarna well was spud on trend with the prior discovery and that it was likely to be a 30-day probe. The rig will now test the Kaliakra discovery, most likely running a 10- to 11-day trial.

Mr Sutherland said too that Kaliakra reserves were estimated to be up to 47 billion cu ft, but that, with other targets, the trend could have 120 billion cu ft (upside case).
Further, he revealed that Melrose was preparing to convert its virtually exhausted Galata gas field for storage purposes next year.

“Galata has a robust formation suited to gas storage,” he said. “The two existing production wells and compression facilities will form the focus and the plumbing revised to allow metering and filtration of gas prior to injection. A third well that was drilled and suspended in eastern part of the field will be tied back to the Galata platform.”

He added that it would not be necessary to use a rig to overhaul the two core wells but that the suspended well would require one.

Crossing to the Turkish sector, Toreador has also reported a 10-m net pay gas discovery. It was late 2007 when the company said that the Bati Eskikale-1 exploration well drilled in the deeper waters of the South Akcakoca Sub-basin (SASB) by operator Türkiye Petrolleri Anonim Ortaklığı had been successful.

All told, a 37-m (121-ft) interval was perforated and tested, yielding a flow rate of approximately 8.8 million cu ft/day.

Toreador said too that Bati (West) Eskikale-1 confirmed that a natural gas trend in the deeper reaches of the SASB project extends to the northwest of the Akcakoca-3, and is the 14th well to successfully encounter gas in the project area.

This glimpse at the Black Sea also includes the Sterling Resources two-well program offshore Romania using the Prometeu jackup – initially the Doina-4 well before moving on to a well on the Ana field discovery (formerly Doina Sister).

Doina-4 came in as a success, with initial results confirming the northerly extension of the gas-bearing Doina Main Sand reservoir, some 1.6 km north of the previously drilled Doina wells. In addition, prospective gas-bearing intervals were noted both above and below the main reservoir body.

Ana-2 was drilled as a follow-up appraisal following the Ana-1 discovery well, which was drilled and tested earlier this year. It too was a success and confirmed the presence of a 39-m gas column in high-quality reservoir sands.

The Ana-2 well also encountered a 5-m gas-bearing reservoir in a shallower horizon at 766 m TVDss. This shallower horizon was also present in the Ana-1 well and will be further evaluated in order to determine its feasibility as a new reservoir.

Another company Chermomor is also active in the Black Sea using a pair of jackups to drill offshore Ukraine. However, it was not possible to glean any details of the current program.

CASPIAN

Unquestionably the heartland of upstream petroleum in Eurasia, the Caspian continues to generate worthwhile discoveries in spite of the lack of full cohesion between its littoral stakeholders – Azerbaijan, Iran, Kazakhstan, Russia and Turkmenistan.

There is a strong familiarity with the Caspian scene throughout much of the offshore upstream fraternity. Basically it is dominated by Azerbaijan and Kazakhstan because of the Azeri-Chirag-Guneshli and Shah Deniz projects (Azerbaijan) and Kashagan (Kazakhstan), while Turkmenistan plods along behind the leaders and is followed by the Russian sector, where there has yet to be production, and Iran, which is generating excitement because the Iran Alborz semisubmersible is in the final throes of commissioning.

Azeri sector

Azeri-Chirag-Guneshli (ACG) remains the backbone oil producer, the development of which is a protracted affair.

The ACG Production Sharing Agreement signed in September 2004 covers the 30-year development of a resource that could eventually reach 5.4 billion bbl of recoverable oil.

Chirag has been producing since 1997 as part of the Early Oil Project (EOP). This was followed by Azeri Project Phase 1 – Central Azeri production in early 2005. Successive phases include West Azeri, which started production in 2006, and East Azeri, on-stream in 2007, as Azeri Project Phase 2, with ACG Phase 3 – Deepwater Guneshli, under way and expected to begin production this year.

By 2010, ACG should be producing over 1 million bbl/day of oil plus 212 billion trillion cu ft/day of gas. The estimated development cost is $8.6 billion to date, with a further $10 billion mooted for the future. And, running like a silver thread throughout the project for the past 11 years is KCA DEUTAG, which holds the drilling services contract.

That same silver thread runs through the BP-operated Shah Deniz field, whose recoverable reserves are estimated at up to 30 trillion cu ft of gas and 1.7 billion bbl of condensate.

The first phase of the field’s development comprises a fixed offshore platform, two subsea pipelines and a new onshore gas-processing plant. First gas was in December 2006.

Discussions are under way about Phase 2 of Shah Deniz, which could more than double production to over 700 billion trillion cu ft/year.

On the exploration front, late 2007 saw BP report a major new gas-condensate discovery on the Shah Deniz concession. Its SDX-04 appraisal and exploration encountered a new high-pressure reservoir in a deeper structure below the currently producing reservoir. It was drilled to a Caspian-record depth of more than 7,300 m (23,951 ft) in the southwestern part of Shah Deniz.

The company said that this discovery represents a potentially significant find. There will be appraisal to fully delineate the new structure in the next few years.

Kazakh sector

This remains a one-pony show in offshore terms, with Kashagan continuing to catch the headlines as delays mount and the Eni-led KCO consortium put on the spot on more than one occasion than the Kazakh government.

This is a huge project of which Phase 1 alone includes the construction of artificial islands, seven processing barges, pipelines and onshore facilities. The hulls of the barges are being built in Romania, and they will be outfitted in Norway.

Phase 1 output is expected to begin at 75,000 bbl/day and is ultimately expected to reach 1.2 million bbl/day. The overall capital cost is estimated at up to $30 billion, and KCA DEUTAG has the drilling contract.

Other development prospects in Kazakhstan include Kurmangazy, Tsentralnoye and Khvalynskoye, all of which discoveries straddle the Kazakhstan/Russian border in the Caspian Sea. KazMunaiGaz of Kazakhstan and Rosneft of Russia signed a production sharing agreement for Kurmangazy in July 2005. Lukoil of Russia and KazMunaiGaz have agreed to establish a joint venture to develop Khvalynskoye.

Russian sector

It is the Russian sector that has generated the most news in 2008, with Tsentrkaspneftegaz, the Lukoil-Gazprom joint venture, making a large oil, gas and condensate discovery on the Severniy Block. Lukoil and Gazprom have said nothing about the size of the find, but speculation points to some 730 million bbl of oil alone.

Tsentrkaspneftegaz was formed in 2003 to carry out the development of Tsentralnoye as well as the Khvalynskoye field on the Russian side of the border with Kazakhstan, while KazMunaiGaz is to operate the Kurmangazy development in partnership with Lukoil.

Also in the news is Swedish independent Lundin, whose Morskaya-1 discovery well on the Lagansky Block has been successfully tested at a combined flowrate of 2,500 bbl/day of 32˚ API oil.

Lundin said in July that two drillstem tests were conducted using the marine drilling complex from which the well was drilled. The Neocomian formation was perforated over a 7-m (23-ft) interval and tested at a stabilized rate of 1,700 bbl/day of oil at a 56/64-in. choke. The Aptian formation was perforated over a 21-m interval and tested at a stabilized rate of 800 bbl/day at a 36/64-in. choke.

The company said recently that Morskaya-1 in fact encountered a major oil accumulation in the Aptian and Neocomian sandstone reservoirs and that a preliminary estimate indicates gross recoverable resources between 110 million and 450 million bbl.

In September, Lundin embarked on drilling the Laganskaya-1 exploration well, also on the Lagansky Block.

The well, with a planned total depth of 2,000 m (6,562 ft), is targeting Cretaceous and Jurassic sandstone reservoirs. The Laganskaya structure is situated towards the southwest of the recent Morskaya discovery but on a different structural trend associated with existing onshore fields.

Lundin CEO Ashley Heppenstall told Drilling Contractor: “The first exploration well early this year on the Morskaya structure was a major oil discovery which is estimated to contain mid case 230 million bbl of recoverable oil within the Lagansky Block. The whole structure, which stretches into adjoining acreage, is estimated to contain double this amount.

“The second exploration well, currently being drilled, will be followed up by a third exploration well in 2009.

“The operational environment is challenging in the northern Caspian due to winter ice and fish breeding seasons, which restricts the windows for drilling activity. In addition, the shallow-water depth of around 2 m has necessitated the construction of a mobile drilling complex which can operate in this environment.”

Laganskaya-1 well is the second in a four-well drilling program planned for 2008-09. The gross unrisked prospective resources for the Laganskaya prospect are estimated at 106 million bbl oil equivalent.

It may come as a surprise, but there has been no offshore production from the Russian Federation’s sector of the Caspian.

However, the first field, Yuri Korchagina, is scheduled to go on-stream in 2010. The recoverable reserves have been estimated at 353 billion cu ft gas and 32 million bbl of oil. Another discovery on the Severny block, Yuzhno-Rakushechnaya, is expected to be developed as a satellite of Korchagina. Lukoil has also stated that the Filanovskogo discovery, made in 2005, could be on-stream in 2011.

Turkmeni sector

Turkmenistan’s offshore patch is mostly associated with a modest Irish company imaginatively name Dragon Oil, one of many minnows to have taken a hammering in the current financial crisis. However, there is little to report other than that Dragon is reportedly looking to secure the jackup Trident 20 (aka Gurtulush) for further drilling. The rig has lately been drilling for Petronas in Turkmeni waters (Block 1).

Iranian sector

We end this rapid cruise with arguably the most exciting piece of news to hit the Caspian in some years – the commissioning of and first contract for Iran’s semisubmersible self-build, Iran Alborz, which is to start drilling for the Iranian company Khazar Oil on Block 6 offshore Iran.

North Drilling Co will manage the project, and technical support is to come from China Oilfield Services Ltd (COSL).

The plan is to drill the first on Block 6 (named Alborz) to a total depth of 700 m (2,297 ft) below seafloor. Having cut its teeth on Block 6, Khazar Oil said that it intends to move the rig to the Chalous Block (Block 29) for further exploratory work.

Iran claims that its part of the Caspian Sea holds 17-44 billion bbl of oil and 232 trillion cu ft of gas. However, it is virgin territory, and it will be many years before the true resource capability of the Iranian sector in fact is.

Rig markets are no longer local. As the global economy and operators’ drilling programs dictate, more and more drilling contractors are finding themselves going into unfamiliar countries with unfamiliar cultures and business practices. For operators, the need to move into new territories may be even more crucial as they seek access to economically recoverable reserves.

In recent years, corruption and bribery issues have pushed to the forefront. For companies in the oil and gas industry, trying to manage anti-bribery and to comply with various laws can be a tough task when operations are so diverse and moving personnel/equipment in and out of countries is an everyday occurrence.

Drilling Contractor spoke with Alexandra Wrage, president of Trace International, on what challenges the industry faces and strategies they can take to address anti-bribery. Trace International is a nonprofit association that pools resources to provide practical and cost-effective anti-bribery solutions for multinational companies.

DC: What are the challenges you see the drilling industry face around the world with anti-corruption?

Wrage: I hear a lot about the tedious, exhausting, low-level backsheesh mentality. This means that when you’re moving equipment, someone has their hand out. Getting things through customs, someone has their hand out. You have problems moving your people, maybe with visas or customs when shipments personal effects.

We refer to that as the hassle factor. They may not be huge amounts of money, so there may be a temptation to just pay it. But the legal risk associated with that is just too great now. Instead, companies find themselves embroiled in endless small disputes over often very petty sums.

DC: What should companies do when faced with demands for petty sums?

Wrage: They have to take a very strong stand because if they don’t, they just mark themselves as targets for the next round. Government officials who are on the take figure out pretty quickly which companies pay and which don’t. If you give in and pay, chances are good that you’ll wake up the next morning and find a whole line of government officials outside your door.

And this is always surprising to people, but companies get a very strong reputation either as a company willing to make these payments or a company that refuses to make them. I spend a lot of time in places like Nigeria and Equatorial Guinea and Yemen, and when I ask government officials which companies pay and which don’t, they can name them. If you have a reputation as a soft touch, you’ll have far more demands.

Obviously, you never want to endanger anyone’s health or safety, so that’s always the exception. Otherwise, you have to take a very strong zero-tolerance policy and mean it. If they keep asking and asking and eventually wear you down, all you’ve done is teach them stamina. You just told them to hang in there.

DC: What about companies worried that if they don’t pay, they won’t get access?

Wrage: That’s usually the first response you get from a company that has been paying – “We don’t believe we can do business if we don’t pay.” But that’s just not borne out by our experience at all. We have over 150 members companies (at Trace International), and oil and gas is our largest community. There are a lot of success stories if you talk to oil and gas companies and oilfield services companies. In fact, there are very few stories that don’t end in success. They do require commitment, resources and management will. You can’t tell your employees, “We’re going to give this a try.” You have to be determined to do it.

In some really tough communities, like Kazakhstan, companies that haven taken a really strong position found that they get pushed around for about 30 days, then the demands just stop. That’s not me being naïve.

They really do, and we have companies that vouch for this.

The rationale is if you are an entrepreneurial bribe taker and you want to enhance your standard of living, you go back to the companies that pay – you don’t waste time on companies that don’t.

DC: So they pick on the weak ones?

Wrage: The companies that do pay often strut around like it’s a sign of incredible business management, but they’re just being complicit in their own extortion – which is a very strange business model.

DC: Are you seeing companies in the oil and gas industry take specific measures to prevent corruption in their own company and among their own employees?

Wrage: Absolutely. There are companies rolling out very sophisticated anti-bribery programs and getting high-level commitment from management. But even something as simple as a companywide e-mail from the CEO saying they would rather walk away from business than risk an illegal payment can make a big difference.

You also have to get the high-level message all the way out to the front line, not just headquarters. Sometimes I see companies do this only at headquarters. That’s important and a good step, but you have to get it to the people on the front line. Then you have to give them a strategy and tools so they can resist demands for bribery.

I spend so much of my time in the developing world, and I see that the people on the front lines are more fed up with (bribery) than headquarters. It is absolutely exhausting to live in a climate where someone is asking you for payment at every turn – sometimes to get through a checkpoint, sometimes to get your own furniture released, or if you want to get a local drivers license. There are millions of ways that government officials can extort payments from you.

DC: So you do see that bribery and corruption are more prevalent in the developing world?

Wrage: The payers are everywhere in the world. There’s no country immune from it. However, typically, the controls in democratic, developed countries prevent the opportunity (for bribery). I’m not suggesting that the police of one country are more moral than police in another country, but there are just more opportunities. If it’s a free for all where the very president of the country is on the take, the message he’s sending all the way down the chain of command is, it’s every man for himself, make a grab for it. Certainly the demand side is far more prevalent (in the developing world).

DC: Are those countries trying to improve and stop corruption?

Wrage: Some countries, yes. They’re taking strong stands and saying all the right things. Some countries, not so much. It’s difficult because the people who stand to gain the most from corruption are the people we’re asking to change.

DC: Are stronger and better anti-corruption laws taking shape around the world?

Wrage: I think we have enough laws. But we don’t have laws of implementation in certain countries, and we don’t have enforcement in the majority of countries. The US is way ahead on enforcement, and we’re starting to see some enforcement in Europe. And there are far more countries that have enforced no cases.

DC: What are some common mistakes companies make in trying to comply with anti-bribery laws?

Wrage: Focusing on just (the oil and gas) industry, I think an insufficiently organized effort. There are a lot of good, decent people in large companies saying we shouldn’t do this, but there isn’t a plan. There isn’t a consistent message.

Some people say, ‘So you have a policy against bribery, big deal.’ But it is a big deal. If the people on the front lines don’t have that to point to, they can’t say, ‘I understand this is the way business has been done in this country in the past, but I can’t do it. I’d risk my job.’ It doesn’t have to be an adversarial or big ethical discussion with the officials. It’s just, we just can’t do this, the risk is too high.

You have to give employees a strong centralized compliance function that backs them up every step of the way. So many companies have good intentions, but they don’t have good programs.

The ingredients of a good compliance program are not that complicated: the message, the training, the auditing, the hot line so they can ask for help when they’re in a difficult situation. They’re not complicated, but, in order to work, they need to fit together as a whole. I think with this industry in particular, that’s what I see most. It’s not a lack of will. There is a high level of frustration with corruption in this industry.

I get frustrated when I see surveys say oil and gas and aerospace and defense are the dirtiest industries in the world. And I say, no, they’re really not. Those are two industries that I see consistently doing more than anybody else.

Ms Wrage is chair of the Women in International Regulatory Law Steering Committee, co-chair of the American Bar Association’s Anti-Corruption Committee, vice chair of the Association of Corporate Counsel’s International Legal Affairs Committee, and a member of the Working Group for the United Nation’s Global Compact 10th Principle. She has been a guest speaker at a recent meeting of the IADC Ethics and Corporate Compliance Committee and is scheduled to discuss anti-bribery at the 2008 IADC Annual Meeting, 6-7 November in Scottsdale, Ariz

In 2007, in order to meet client demands for high-specification, fast-moving rigs with improved safety and minimal environmental impact, Ensign Energy Services decided to deploy two Automated Drilling Rigs (ADR) from Canada to Australia. These environmentally friendly rigs have small footprints and offer a safer working environment for personnel through automation. Their trailerised design saves time when moving between locations and minimises nonproductive time.

In order to move the rigs into Australia, Ensign embarked on a rigorous cleaning campaign to ensure quarantine requirements were met. Rig #48 was destined for Barrow Island, a Class A Environmental Reserve requiring special quarantine measures.

Ensign and the client, Chevron, utilised the services of Toll, a sub-contract company approved by the Western Australian government that ensured quarantine measures were policed and strictly maintained. Ensign was aware of requirements of the Australian Quarantine Inspection Service (AQIS) to import rigs to Australia. However, acting on advice that Toll inspected to a higher standard for Barrow Island, an AQIS inspector was not engaged to inspect Rig #48 equipment in Canada.

Subsequently, Ensign was advised that due to a bureaucratic turf war, AQIS would not accept the Toll inspection even though Toll had forwarded detailed reports and photographs of the cleaning process to AQIS. As a result of AQIS not accepting Toll’s inspection, Rig #48 had to be diverted from its direct shipping route to Dampier to be offloaded in Darwin for AQIS inspection. This diversion cost Ensign approximately A$550,000.

With the shipment of Rig #50, Ensign engaged an AQIS inspector to travel to Nisku, and the rig entered the Port of Brisbane in Queensland with no difficulty.

Even though the rigs were working in Canada, Ensign was aware that certain modifications had to be made to meet Australian state regulations. The electrical regulations in Western Australia (WA) are the most stringent for land rigs that Ensign has encountered globally.

Even though Rig #48 was extensively re-wired in Canada to meet WA regulations, with WA government-approved mechanical and electrical inspectors overseeing the work, all electrical cable joints subsequently had to be replaced when the rig arrived on Barrow Island. This resulted in an additional cost to Ensign of approximately A$250,000.

Both rigs were designed to be highly mobile units, with some units on Rig #48 trailerised and all units on Rig #50 trailerised. On Barrow Island, mobile equipment does not require registration, so Rig #48 could be freely moved.

However, due to the areas in which Rig #50 was going to operate, it required the trailers to be registered. Here Ensign encountered another set of bureaucratic setbacks. The importation of vehicles and trailers to Australia is administered by the Federal Department of Transport and Regional Services (DOTARS), now the Department of Infrastructure, Transport, Regional Development and Local Government. Through a transport consultant, Ensign made an application for DOTARS approval, which was required by state governments in order to register each trailer. Because the equipment was specially designed, DOTARS regulations required special departmental administrative approval as there is no category covering mobile oil drilling equipment.

Ensign was advised, however, that a special application could be made to register low-volume usage vehicles – which was not stated in guidelines. This turned out to be useless in this exercise as each vehicle comprises approximately eight loads, and this approach is limited to the registration of three vehicles per year per company.

Upon arrival of the rig in Queensland in late September, the local Department of Transport inspected, weighed and measured the Rig #50 trailers and made recommendations to Ensign regarding the change-out of some sections of the brake system, as well as side and tail lights. This was undertaken because DOTARS approval had been delayed due to the federal election and the change-out of departmental personnel; therefore the Queensland transport department was unable to register the trailers.

In order to meet client commencement deadlines, a decision was made to move the rig to the first drilling location using heavy-duty transport floats. As of February 2008, DOTARS approval had still not been received, and the first eight wells were drilled with the highly mobile rig having to be moved between wells using heavy-duty floats and cranes for loading. This resulted in additional time and costs of approximately A$220,000.

Recent indications are that Queensland Transport may be prepared to issue special permits for the trailers to be moved unregistered, provided that Ensign give sufficient notice of the routes to be taken and provide escort vehicles for this purpose.

Other transport contractors who have mobilised new twin-steer oilfield rig trucks to the Cooper Basin have encountered similar difficulties, and these specialised new vehicles are having to be floated between drilling locations. The cost is ultimately passed on to the end user.

Other examples of bureaucratic and administrative procedural issues exist. One case in point was the procurement by the Metropolitan Fire Service in South Australia of a command vehicle that was constructed in Queensland and lay idle for more than 12 months while transport registration issues were resolved.

Given the cost and administrative issues in dealing with the Australian bureaucracy at various levels, Ensign will deliberate long and hard about deploying any additional highly mobile ADR-type rigs there. Being a global drilling contractor, Ensign considers contract opportunities in other countries to be simpler to execute, and it is easier to deploy existing rigs to so-called “developing countries” in Africa, the Middle East, Asia and South America.

Surely this is a loss to the Australian petroleum exploration industry and requires governments and governmental departments to work together to ensure the best equipment is available in this country to continue the exploration and development hydrocarbon resources.

John Bushell is vice president international marketing with Ensign Energy Service’s International Division. He has more than 20 years of experience in the contracting drilling industry and holds undergraduate and post-graduate qualifications in technical and commercial disciplines.

This article is based on a presentation made at the APPEA 2008 Conference & Exhibition, 7-9 April, Perth, Australia.

In a world where perception is often reality, an industry that is perceived, albeit unfairly, as dirty, dangerous and greedy can suffer a crisis of image that threatens its foundation and future. But getting the truth out can be a challenge.

In the drilling industry in particular, efforts have accelerated to communicate the advances in technology and greater focus on HSE that are transforming the way contractors do business.

“The industry has had a black eye regarding safety and environmental stewardship, and while it is still a difficult and dangerous business, we’re doing a lot of things right,” said John Lindsay, executive vice president of domestic and international operations for Helmerich & Payne International Drilling Co and 2008 IADC chairman.

Maersk Drilling has put steps in place to duplicate its safety record with an environmental one as well. “Safety has always been a top priority in our company and has become important for the entire industry, including the contractors, rig owners and operators,” said Claus Hemmingsen, CEO of Maersk Drilling and partner at A.P. Moller – Maersk. Mr Hemmingsen serves as 2008 IADC vice chairman.

“For more than 20 years, we have been building some of the most superior rigs in the industry, both in terms of safety and from an environmental standpoint, but we’ve never put much effort into telling people about that, except those we work for directly,” he said.

“I certainly expect to see that changing within the industry as a whole to work together to benchmark our performance and focus on real efforts to improve,” said Mr Hemmingsen, who is preparing for his ’09 IADC chairmanship. Earlier this year, IADC established the Environmental Policy Advisory Panel (EPAP) to formally address the industry’s environmental activities and image.

Noble Drilling has created a system-wide culture of HSE responsibility for its 6,000 employees worldwide.

“I think the industry has a worldwide image problem, operators and contractors alike, and that’s a pity,” said Ronald Hoope, Noble commercial director, based in The Netherlands. “We are known to be a business that is not environmentally friendly, but that is changing as we are implementing stringent procedures and policies and seeing more technicians and well-educated people coming to the offshore industry. Offshore is not visible, so the industry needs to do a better job of promoting itself as being safe and environmentally responsible.”

How did we get here?

To understand how the industry reached this crossroads, it is important to understand where it has been, and to take a reality check on public perceptions.

In the case of the US oil and gas industry, that reality check came three years ago with a major shift in external audience engagement. Industry leaders recognized it was time to educate the public and policymakers in a big way about a little-known truth: Oil and gas drilling is safe, clean and technologically advanced, and earnings are being reinvested in exploration that costs billions of dollars.

“What was needed was a thorough understanding of what the industry is all about,” said API president and CEO Red Cavaney.

After measuring consumer and government attitudes through research, the industry embarked on what Mr Cavaney calls “the battle for the public mind”: a focused, collaborative, multi-faceted effort culminating in one mission – educational advocacy.

“For several decades, companies in the industry appeared to view their advertising as more focused on product and brand, and not much in institutional advertising or education,” Mr Cavaney explained.

But events such as the 1969 oil spill off the coast of Santa Barbara in California prompted environmental concerns among the general public, which some believe led to the ban on offshore drilling.

“When impacts on public policy development began to shift outside the domain of state legislatures and Congress, to where the public had a much stronger voice in influencing policymakers and elected officials, the industry was slow to change with the times,” Mr Cavaney continued. “As a result, for several decades, the stronger voices being heard were opponents of the industry. So you have at least one or two generations of people who have grown up hearing principally the negative side of the oil and gas industry.”

The industry began to address the problem in the late 1990s, but efforts were limited because not everyone believed there was a problem. It was also questioned whether audience engagement, advertising and education could really change minds, he explained.

The “game changer” came in the wake of the 2005 hurricanes. “After Katrina and Rita, the industry performed in a Herculean manner, unlike anything that had occurred before in terms of minimizing lost lives, getting people to rally and respond, bringing refineries back online, getting offshore back producing and pipelines to go back online,” Mr Cavaney said. “And when all was said and done, virtually nobody went without the natural gas or other fuel products they needed.”

Much to the industry’s surprise, instead of receiving recognition for a job well done, the opposite happened. Public outcry over the high price of gasoline sparked hearings in Washington, D.C., where oil company executives were criticized for violating laws and being irresponsible.
“That served as an absolute wake-up call and underscored the understanding throughout the industry that we did not have an option on whether to engage external audiences or not,” Mr Cavaney said. “We needed to do it.”

What resulted is a broad-based effort that includes national advertising promoting the industry’s clean technologies, outreach programs, increased visibility in local communities and specific audience engagement. Technology is a key element of the message.

“We found that the more people understand the extent to which technology drives our business, their appreciation and understanding of our industry as being important to them in the future is increased,” Mr Cavaney said. API began mobilizing “tech tours” featuring interactive displays to college campuses and state capitals.

“What we’ve seen happen is exactly what we hoped,” he said. “When people begin to understand some of the basics regarding the industry and its role in providing energy, common sense prevails over a lot of opposition.”

One example of that shift came late this year when the federal government lifted the 26-year-old ban on US offshore drilling. Mr Cavaney noted that as the price of gasoline moved toward $4 per gallon, people’s attitudes about offshore drilling shifted from three in 10 in favor to seven in 10, or better, in favor.

The collaborative nature of the educational advocacy effort is critical. No one element is considered to be more successful than the others. “You use different approaches for different audiences and different objectives,” Mr Cavaney explained. “Advertising is good for conveying a simple message. If you’re trying to get a more technical message across … then print medium or personal contact/direct audience engagement is a much more powerful way to do it. Radio is good for repetition and reinforcement. They are all important.”

Education efforts also are being ramped up by nonprofit agencies providing materials for schools and museums, and through audience engagement with trade groups.

“We have been dismayed at how ignorant and uninformed people, including elected officials from oil-producing states, are about our industry,” said Brian Petty, IADC senior vice president – government affairs. “We have gone into classrooms, and kids’ impressions are of an industry that is dirty and dangerous, kills fish and is bad for the environment.”

Offshore drilling is a key example of why the industry has a responsibility to “step out” in its efforts to inform the public, Mr Petty pointed out. “Oil and natural gas royalties is the second-largest source of revenue for the US government, after income taxes.”

The National Ocean Industries Association (NOIA) represents the offshore energy industry and works closely with associations that represent key end users of energy, like the American Farm Bureau, the National Association of Manufacturers and the American Chemistry Council. “Our message is that the oil and gas industry, particularly offshore, is more advanced than most people think it is,” said Michael Kearns, NOIA director of external affairs.

“The technology today is cutting edge and rivals the space program in terms of the places we’re able to operate,” he continued. “Add to that an enviable safety record. Also, we talk about the fact that this is a vital energy source for the nation.”

An example of where NOIA has made an impact is with the Farm Bureau. “Farmers across the country are finding their fertilizer costs are going up because natural gas is a necessary prerequisite in making fertilizer. So their energy costs are going through the roof,” Mr Kearns said. “So, when inland farmers realize that the resources beneath the Outer Continental Shelf belong to the United States as a whole, they want to know why they are being prevented by coastal states from having access to them.”

Mr Kearns emphasized that NOIA does not advocate one form of energy over the other. “The fact is, as a nation and as a world, we need all the energy resources we can find,” he said. “And it doesn’t make sense for us to simply cut out consideration of offshore oil and gas, especially when the environmental record is so much better than the general public thinks it is.”

Going on the offensive

Oil companies – the “face” of the industry – also have embarked on television advertising campaigns to dispel the outdated perceptions. Some ads acknowledge the need for developing alternative energies such as solar, wind and biofuels, a goal supported by API and other groups that are calling for a balanced energy policy.

“A study done last year for the Department of Energy, ‘Facing the Hard Truths,’ concludes – and this is backed by other studies – that for our economy to continue to enjoy the economic growth and improved standard of living we’ve had over the last 10 to 20 years, we’re going to need all the energy we can produce in an environmentally sensitive way here in the United States,” Mr Cavaney noted. “We are supporters of alternative energy, all economically viable forms of it.”

ExxonMobil has put education at the center of a program that includes national advertising, an employee speaking program to generate awareness about how the company is meeting energy challenges, media relations and corporate citizenship.

“There has never been wider spread interest in energy,” said spokesman Alan Jeffers. “People have an incredible appetite for information about the industry, and it’s important for us to provide that directly.”

A TV campaign launched in June focuses on commitment to science and technology that is environmentally clean. “The advertising is not promotional, but designed to increase awareness and energy literacy,” Mr Jeffers said. “We need people to understand that the investments it takes to develop new supplies of energy are massive.

“We employ 14,000 scientists and engineers throughout the world,” he continued, noting that ExxonMobil was the founding sponsor of the National Math and Science Initiative in the United States. “We’re a high-tech industry that is challenged to tap new energy supplies and at the same time reduce greenhouse gas emissions.”

The speaking program encourages people to visit the company’s website, where they can learn about corporate citizenship efforts and the ExxonMobil Foundation, which in 2007, together with employees, retirees and affiliates, donated nearly $207 million to HSE and educational causes worldwide. In 2005, the company launched the Educating Women and Girls Initiative in developing countries to improve health conditions, reduce poverty and slow the spread of HIV/AIDS. More than $12 million has been invested in the program in Africa.

At Chevron, the supermajor is delivering an energy efficiency and conservation message through its “I Will” campaign.

“Our intent is to raise awareness of the importance of energy efficiency and conservation and to lead the discussion about what we can do as individuals every day to increase energy savings,” said representative Kimberly Beman. The campaign reflects a culture of conservation the company has embraced since 1992, she said. “As a company, we are 27% more efficient that we were in 1992.”

Chevron’s website features interactive tools like the energy generator, which “demonstrates how simple, individual actions can yield large energy savings,” Ms Beman explained. “For example, if 1,000 people lower their thermostat in the winter by one degree in an average US residence, they will save enough energy to power a hospital for 10 days.”

Better rigs, better technologies

For the drilling and service industries, new technology has enabled them to tap previously unattainable resources in an environmentally friendly way. Many companies are increasing their visibility as good corporate citizens as well.

“The industry has come a long, long way since some of the environmental incidents of the 1960s, ’70s and ’80s,” said Mr Lindsay at H&P. He noted that onshore spills have been greatly reduced, and offshore spills have been all but eliminated.

The FlexRig, an AC-drive design equipped with state-of-the-art technology, has significantly impacted H&P’s drilling operations in Colorado’s Piceance Basin, in the Rocky Mountains, and in heavily populated areas of the Barnett Shale by reducing rig footprint, noise, traffic and improving efficiency.

“In 2005, we joined with Williams Companies to look at ways we could improve our environmental footprint and change the way wells were being drilled in the Piceance Basin,” Mr Lindsay said. Conventional rigs were drilling three to five wells on a pad and being moved manually from well to well, which required bringing in trucks and bulldozers.

“Working with Williams, we designed a rig that took offshore technology to an onshore environment,” he continued. “The FlexRig could drill 22 wells on a single, 1.5-acre location. Once on a new location, we didn’t need outside trucking or bulldozer companies to move the rig on the remaining 20-plus wells. It was all done with internal hydraulics on the rig.”

The design has allowed the company to drill in much shorter periods of time, thereby lessening impact on wildlife and local residents.

“This was a game-changer,” Mr Lindsay said. “It really made a difference in terms of reducing noise, truck traffic and building fewer locations. The new rigs also have the latest technology diesel engines, which reduce emissions, improve fuel efficiency and burn less fuel.

“And on the safety side, we’ve significantly cut the number of incidents because the rig design is much safer than rigs designed 30 years ago,” he added. “As drilling contractors retool their fleets, they are seizing an opportunity to utilize safety-by-design that heretofore has not been seen.”
The FlexRigs also enable H&P to simultaneously produce gas and drill. “They are able to frac wells in batches, which offer some attractive benefits,” Mr Lindsay explained. “Advantages include fewer frac trucks going up and down the road; re-using and thereby conserving water; and limiting the frac footprint. In this case, everyone wins.”

In the Barnett Shale, the FlexRig has been employed in populated areas, next to schools and residential areas where children play and where truck traffic and noise are big concerns. “Drilling is a 24/7 activity,” Mr Lindsay said. “People want rigs that are quiet. One of the many advantages of AC-drive technology is the elimination of the screeching brake heard with a conventional rig that echoes for miles. The AC rigs drill faster so, again, we’re able to develop the fields more quickly, and get the drilling rigs out of the public eye more quickly.”

The FlexRig also has been instrumental to fostering good community relations. “Through our work with Devon Energy, Encana and other E&P companies in the Barnett Shale, we’ve been able to use the FlexRig as recognition that we are doing things differently,” he said. “We also focus our people’s efforts on not littering in the area, driving cautiously and to treat these areas like it’s their own. The bottom line is that this is the right thing to do.”

At Maersk, Mr Hemmingsen points to his company as an example of action he would like to see the industry take. In 2007, the company put an environmental reporting system in place and began collecting data on emissions and fuel consumption to establish a baseline for improvement. “Now that we have more than a year of data, we are starting to set targets for our performance,” he said.

Another important issue is making the industry an attractive one for people to join. “I think we have a huge challenge in attracting people to the industry in general due to growth of the industry and the demographics of the current workforce,” Mr Hemmingsen pointed out. “We need to make an effort to communicate that the drilling business is a good career platform and holds good potential and a good record.”

Maersk Drilling also has been visible in communities where the company has a long-term presence.

“For example, we have been in Norway for close to 15 years and have been engaged with the local communities both on an advisory level and in the community at-large,” Mr Hemmingsen said. “In Venezuela, where we have been operating for 20 years or so, we have huge programs where we work for the betterment of local communities, assisting with education efforts and local projects.”

At Noble Drilling, “HSE is embedded in our culture and part of our daily operations in everything we do,” Mr Hoope noted. “Each year we provide leadership courses to all our crews worldwide, in effort to mold responsible behavior and have everyone in the company moving in the same direction.” The company considers the $2 million it spends on the course to be an investment.

“We also sponsor Noble Safety Day, where we invite our third-party contractors, which are related to 25% of our incidents, to come and learn about how Noble works, including our policies, procedures and protective equipment,” he said. “Our incident records are already low, but we want to reduce incidents even further, to zero.”

Noble also has daily and weekly safety-related conference calls, so if an incident occurs on a rig, the company can implement measures if needed.
“We promote waste reduction and recycling of waste in our efforts to be environmentally focused and not leave any footprint behind,” Mr Hoope said. “We are very aggressive in cleaning rainwater. Any drip of oil from a cable is cleaned.”

Noble also produces an annual Sustainability Report and is listed on the Dow Jones Sustainability Index. “This shows that we are very transparent because we publish our problems and our mistakes,” Mr Hoope noted.

The company also is visible in the communities where it operates. “We support charities and work as much as we can in communities to hire local people, vendors and contractors, such as rig builders,” he pointed out. “Our next step is to go to the local schools and recruit employees who are educated and can provide the technical expertise the industry needs,” he said. “Education is better for safety.”

Giving back

Halliburton’s corporate citizenship efforts include volunteer efforts worldwide and a corporate giving program that in 2007 raised nearly $353 million for education, health and social services organizations, the environment and arts. Employees volunteered more than 30,000 hours in 2007 in communities in Russia, India, Egypt, Saudi Arabia, Brazil, Venezuela, Nigeria and Norway.

“At Halliburton, we believe in giving back to the communities where we live and work – it’s as much a part of our culture as providing exceptional service to the customer,” said Diana Gabriel, senior manager, communications for the company. “We support a wide variety of charitable organizations around the world, with an emphasis on those that are most important to our employees, customers and communities.”

Donating blood, raising money for medical research, tutoring and mentoring students, delivering meals to the elderly, planting trees and helping with environmental cleanup are among ways employees can volunteer, Ms Gabriel said. Another program, Giving Choices, allows employees to donate to the charity of their choice.

“Another way we contribute to our local communities is through Halliburton Volunteer Councils, which are created by local employees who establish their own bylaws, elect officers and decide which local organizations to support,” she said. “All around the world, you’ll find Halliburton employees building playgrounds, feeding the hungry, raising money to fight diseases and caring for those who need our help the most.” The councils partner with local charities to focus on the immediate needs of the community.

“Being a considerate and helpful neighbor has been fundamental to Halliburton’s culture from the earliest days of the company,” Ms Gabriel said. “We believe that improving the quality of life in the communities where we operate is good business. It’s the right thing to do.”

Ineffective perforation can adversely affect the completion of fracture stimulated wells in several ways. If the interval is to be tested prior to fracturing, a clean connection to the formation is required to facilitate meaningful data acquisition. Excessive perforation damage can mask true formation potential and lead to incorrect diagnosis and decision-making. Inadequate perforations can result in significant fracture tortuosity, increasing formation breakdown pressure – occasionally beyond the capacity of surface equipment or design rating of the well.

Finally, limited-entry perforation – a common technique for diverting a treatment across multiple fracture initiation points – demands that as many perforations as possible are open and can accept treatment fluids.

Low perforating efficiency and variations in perforation cleanup associated with heterogeneous formations can cause uneven treatment distribution and sub-optimal completion.

Traditional methods for achieving clean perforations depend on creating a pressure gradient between formation and wellbore to induce flow and remove debris from the perforation tunnels. This can be difficult to accomplish, especially in low-pressure reservoirs. Underbalance cleanup favors intervals with higher flow potential – typically those with greater permeability – and may result in low perforation efficiency in poor or variable quality zones. Operators of wells requiring fracture stimulation are therefore faced with a significant challenge to find reliable and cost-effective perforating methods.

A new class of reactive shaped charges has recently been introduced that generates a powerful secondary effect within each perforation tunnel immediately after it is formed. The reaction supercharges each tunnel, causing a surge of flow into the wellbore that removes all compacted debris and the near-tunnel crushed zone that would otherwise impair flow performance.

Since this effect is independent of rock properties and wellbore conditions, a very high percentage of clean tunnels can be obtained across the entire interval without necessarily perforating in an underbalanced condition.

This article describes the new charge technology and reports on its successful deployment in more than a dozen wells for operators in Canada. Specific examples are used to illustrate how the system facilitates pre-frac evaluation, fracture initiation and limited entry fracture stimulation.

Introduction

Shaped charge perforators are the dominant method used to create a flow path between formations of interest and the wellbore in a cased and perforated completion. The vast majority of perforated completions depend on the use of shaped charges because of the relative speed and simplicity of their deployment compared with alternatives, such as mechanical penetrators or hydro-abrasive jetting tools. However, despite these advantages, shaped charges provide an imperfect solution.

Shaped charges are formed by compressing high explosive powder within a metal case using a conical or parabolic metal liner (Figure 1). When the explosive is detonated, the symmetry of the charge causes the metal liner to collapse along its axis into a narrow, focused jet of fast-moving metal particles (Figures 2a-2c).

When the charge is positioned perpendicular to the wellbore casing, the jet penetrates the casing, and the surrounding cement sheath and formation rock (Figures 2d-2e). This is a displacement mechanism where the steel, cement and rock are pushed aside by the jet, a process that continues until the speed of the jet falls below some critical velocity and cannot penetrate further. The effectiveness of this perforation tunnel is determined by its geometry and quality.

Tunnel geometry, quality

The distance the tunnel extends into the surrounding formation, commonly referred to as the total penetration, is a function of the explosive weight of the shaped charge; the size, weight and grade of the casing; the prevailing formation strength; and the effective stress acting on the formation at the time of perforating.

Effective penetration is some fraction of the total penetration that contributes to the inflow or outflow of fluids. This is determined by the amount of compacted debris left in the tunnel after the perforating event is completed. Effective penetration may vary significantly from perforation to perforation, and there is currently no means of measuring it in the borehole. The effective penetration determines the effective wellbore radius, rw, an important term in the Darcy equation for radial inflow:

Effective penetration becomes even more significant when near-wellbore formation damage has occurred during the drilling and completion process – for example, resulting from mud filtrate invasion. If the effective penetration is less than the depth of invasion, fluid flow may be seriously impaired.

A further impairment to flow is caused during the perforating process when fractured sand grains, cement particles, metal particles from the disintegrating liner and other fine debris are displaced by the jet and compacted into the pore throats of the surrounding rock. This zone, commonly referred to as the crushed zone, is typically on the order of ¼-in. thick and has been shown to have permeability one-tenth or less that of the undamaged rock. The crushed zone forms a major component of perforation skin unless it can be removed during the perforation event or some subsequent operation.

Other factors contributing to the overall effectiveness of the tunnel as a flow conduit are: casing entry hole diameter (a function of shaped charge design and casing size, weight and grade); tunnel diameter (also a function of shaped charge design, rock strength and effective stress); tunnel fill (although loose fill is generally highly permeable and may be ignored); and the presence of any cracks or fractures extending into the formation from the tunnel wall.

A high-quality perforation

Various approaches are taken to optimize the geometry and quality of the tunnel, either through remedial operations during or after the perforating event or through modification of the perforating system configuration.

Underbalance perforating is the most common optimization technique, whereby the hydrostatic pressure in the wellbore is reduced prior to perforating to create a pressure difference between the formation and wellbore. As the tunnel is created, this pressure difference induces flow from the formation towards the wellbore. Given sufficient pressure difference and formation permeability, enough flow velocity can be generated to destabilize the crushed zone and convey the plugging material into the wellbore. Some, or all, of the compacted fill may also be removed from the tunnel tip.

Dynamic underbalance techniques take advantage of the pressure difference existing between the perforating carrier (sealed at atmospheric pressure) and the wellbore (hydrostatic pressure) at the time of detonation. As a result of this pressure difference, wellbore fluid surges into the gun immediately after detonation, causing a locally sustained pressure drop in the wellbore across the perforated interval. This tends to induce a greater surge of flow from the newly formed perforations than static underbalance alone, thereby enhancing the degree of crushed zone and compacted fill removal.

Unfortunately, both static and dynamic underbalance techniques are sensitive to formation permeability and the amount of pressure difference that can be created. When the formation permeability or reservoir pressure is too low, insufficient flow can be induced and tunnel cleanup is limited. Permeability contrasts within the perforated interval can result in cleanup being limited to only the zones of better permeability from which significant surge flow is obtained, eliminating the underbalance before tunnels in poorer zones have the opportunity to clean up.

In cases where below-expectation well performance is attributed to poor perforation cleanup, operators must either resort to more complex and costly techniques – such as acid stimulation, coiled-tubing deployed jetting tools, or fracture stimulation – or accept a sub-optimal connection between the wellbore and the formation.

Effect of sub-optimal perforations on pre-stimulation testing

In low-cost operating environments, the need to apply secondary cleanup techniques after perforating may significantly impact the economic viability of a well. Where hydraulic fracturing is necessary in order to obtain economic flow rates, some impairment to unstimulated inflow potential may not be of consequence. However, it is often desirable to measure the unstimulated productivity of an interval in order to estimate its likely productivity after stimulation, to design the stimulation itself appropriately, or even to determine whether the zone is worth stimulating.

Damaged perforation tunnels will cause the flow rate measured during a pre-stimulation test to be unrepresentative of the true flow potential of the interval. Since tunnel geometry and quality created in the wellbore cannot currently be measured, the operator must assume or infer the degree of damage based on past experience, rules of thumb and (rarely) on laboratory experiments carried out under representative conditions. This uncertainty compromises both the ability of the operator to make sound stimulation design decisions and any subsequent evaluation of stimulation treatment success.

Fracture stimulation consequences

Fracture stimulation involves raising the wellbore pressure to the point at which the surrounding rock fails, resulting in the creation of a fracture. This is typically carried out by pumping fluids into the well at high rates and pressures (hydraulic fracturing) or by igniting gas-generating material within the wellbore adjacent to the perforated interval (propellant fracturing). Hydraulic fracturing typically results in fractures extending tens to hundreds of ft from the wellbore – depending on the amount of fluid pumped above the fracture propagation pressure. Propellant techniques generate fractures extending 5-20 ft from the wellbore, and are generally used to overcome near-wellbore damage or in situations where larger fracture treatments risk extending into a water-bearing interval.

Perforations play a critical role in any stimulation treatment because they form the only connection between the wellbore and formation. However, arriving at an optimum perforation design can be difficult because essentially all perforated completions are damaged. The residue from the perforating charge plugs the end of the perforation tunnel, and the rock surrounding the perforation tunnel is pulverized and compacted by the explosive shock of the perforating event. The perforating event is so fast that the associated rock deformation and compaction exceed the elastic limit of the rock and result in permanent plastic deformation.

Along with changes in porosity and permeability, the in-situ stress in the plastically deformed rock is also substantially changed, forming a stress cage extending several inches beyond the actual dimensions of the tunnel.

The compacted zones around the perforation can be so highly stressed that the pressure required to initiate a fracture is significantly greater than the measured fracture gradient of the unaltered rock. In extreme cases, the altered rock cannot be broken down before surface equipment limitations are reached. When breakdown is possible, the induced fracture will try to follow a path of lower stress, through unaltered rock, resulting in increased near-wellbore pressure drop, commonly known as tortuosity.

Severe pressure losses may limit the flow rate that can be delivered into the fracture with the available pump capacity and completion constraints. This will limit the size of the fracture that can be created and may result in the operation being terminated prematurely to avoid screen-out (a situation where proppant added to a hydraulic fracture treatment in order to hold open the fracture can no longer be transported into the formation and fills the wellbore, requiring expensive remediation). Final fractured well productivity will also be damaged as a result of the low conductivity channel established at the wellbore.

Limited-entry stimulation

In situations where several intervals in the same well require stimulation and it is advantageous to perform such stimulations in one operation, treatment fluids must be distributed across the different intervals in order for each to be stimulated effectively. This process is called treatment diversion and is critical to achieving optimum productivity as a result of the stimulation treatment.

Limited-entry perforation is a popular diversion method because of its relative simplicity and low cost compared with alternatives such as ball sealers and self-diverting treatment fluids. The technique involves perforating a carefully calculated number of holes across each interval in order to restrict the flow rate that can enter each zone. This theoretically ensures that the total flow rate is distributed in proportion to the number of holes created in each zone. In reality, the perforations will not all clean up equally and will therefore take fluid at different rates.

Poor or inconsistent cleanup will mean that the effective number of perforations is less than the actual number of shots. This may vary from interval to interval, depending on formation properties and their influence on tunnel cleanup, causing the actual distribution of treatment fluid to deviate from the theoretical design. In severe cases, some zones may not be stimulated at all.

Enhanced perforation cleanup

Each of the scenarios described above provides an opportunity for enhanced perforation cleanup, preferably achieved as part of the primary perforating operation and not by introducing additional operational complexity or cost. If clean perforation tunnels can be reliably delivered irrespective of formation properties and without requiring the application of a large pressure difference, pre-stimulation testing will yield a more accurate measure of the intervals production potential, fracture stimulation treatments will be completed without reaching equipment pressure limitations or risk of screen-out, and limited-entry perforation will become a more reliable method for multi-zone stimulation treatment diversion.

New Shaped Charge Technology

A new class of shaped charge has recently been introduced that uses novel liner metallurgy to create a secondary reaction in the perforation tunnel immediately after it has been formed (Figure 2f). The reaction takes place in less than 100 microseconds and can therefore be considered part of the perforating event.

The reaction is highly exothermic, which, under the confined conditions within the perforation tunnel, results in the generation of a very short, sharp spike in pressure. The magnitude of this super-charging effect has been measured in the 50,000-80,000 psi range during laboratory experiments carried out by the manufacturer. The energy released per unit mass of reactive material is of the same order as that released by TNT, although the total energy released per tunnel is relatively low because only a fraction of the shaped charge liner is composed of reactive material.

Relief of this pressure into the wellbore (being the path of least resistance) causes a surge in flow, which expels debris from the tunnel (Figure 2g). Laboratory experiments under representative conditions (carried out in compliance with API recommended practices for perforator evaluation) indicate that all compacted fill is removed from the tunnel tip and the entire crushed zone is removed from the tunnel wall.

Furthermore, in most cases, the pressure spike is sustained long enough for a small fracture to initiate at the tip of the tunnel (Figure 2h). This is of significant benefit during subsequent stimulation operations.

Figure 3 shows tunnels created during single shot perforation experiments using natural rock targets under conditions representative of the downhole environment. Figure 3a shows a classical tunnel created with a conventional charge, and Figure 3b shows a tunnel created with the new class of reactive shaped charge.

The cleaning effect introduced by this class of charge offers a significant advantage over conventional products and addresses many of the challenges described in the introduction. This cleaning effect is independent of the formation properties, provides a driving force at least one order of magnitude greater than conventional underbalance (in excess of 50,000 psi versus typically less than 5,000 psi), and takes place in each tunnel independent of the others.

Methodology

Although the geometry and quality of tunnels created with the new perforating charge have been extensively tested and compared with conventional technology in the laboratory, benefits prior to and during fracture stimulation can only be assessed during actual well operations. The new charge has been deployed by numerous operators across North America and in other regions of the world. This article focuses on examples from Western Canada, where the technology has been evaluated in fields with significant numbers of existing wells for comparison purposes.

The primary method for characterising the near-wellbore region in order to compare the efficacy of the new and conventional perforating systems is a step-down test, carried out during a mini-frac (also known as a data frac) prior to the main stimulation treatment. The mini-frac is used to obtain a direct measurement of formation properties, such as the breakdown gradient and fluid leak-off coefficient, so that the treatment design can be fine-tuned prior to execution.

The step-down test involves pumping a constant fluid into the well at several distinct rates while measuring pump pressure. By combining this information with the other parameters calculated as a result of the mini-frac, near-wellbore pressure losses, perforation friction, and the number of open perforations can each be estimated. The equation at right is used to predict perforation friction pressure as a function of rate, the number of perforations taking fluid, the diameter of each perforation (obtained from manufacturers’ surface tests), and the discharge coefficient. The discharge coefficient may be estimated from the perforation diameter, assuming a round perforation, or measured empirically during tests at surface.

Predicted pump pressure is plotted against measured pump pressure at each of the test rates. Since the other variables are essentially constant, the number of open perforations and the discharge coefficient can be iteratively adjusted until a good match is obtained between predicted and measured values.

Comparison of these results between wells perforated with the new shaped charge and wells perforated with a conventional system will indicate whether the cleaning effect delivered by the new charge is of material benefit under field conditions.

Results

Wells perforated with the new reactive charges across five formations were analyzed in terms of fracture initiation pressure, near-wellbore pressure losses during fracture stimulation, and treating power requirements.

The first analysis presented features two wells typical of the overall data set, one perforated with a conventional system and one perforated with the reactive system. Differences in each of the parameters of interest are examined, based on step-rate data gathered during mini fracs (which were only performed on selected wells in the total population). The second analysis compares treating power requirement across a population of wells, a subset of which were perforated with the reactive system.

Step-rate test results

This example features two wells completed at a depth of approximately 2,500 m in the Rock Creek sandstone formation in West Pembina. Wells in this area are typically perforated and hydraulically fractured.

Problems are occasionally encountered with excessive breakdown pressures.

In this example, Well A was perforated using a 3-m long, 3 3/8-in. (86-mm) diameter, expendable hollow steel carrier loaded with regular 23 gram, deep-penetrating charges at a density of 9 shots/m, and 60˚ phasing. Well B was perforated with 4.5 m of 3 3/8-in. (86-mm) diameter guns distributed across a gross interval of 35 m, loaded with the new reactive shaped charges at a density of 6 shots/m, and 120˚ phasing.

The total number of shots in each case was 27.

Table 1 shows the formation breakdown pressure, breakdown gradient and fracture propagation gradient. The data indicate that although Well B exhibited a much higher fracture gradient (24.2 kPa/m versus 18.2 kPa/m), the breakdown gradient was actually less than that measured in Well A (26.9 kPa/m versus 28.0 kPa/m).

Figure 4 shows total near-wellbore pressure losses calculated from the step-rate test. At a typical treating rate of 2.5 cu m/min, Well B (new charge) experiences only 2,800 kPa pressure loss compared with 11,000 kPa in Well A (conventional charge). Figures 5 and 6 show the calculated pressure losses due to tortuosity (near-wellbore pressure loss) and perforation friction. Perforating with the new charge almost eliminated tortuosity (<200 kPa at 2.5 cu m/min versus 4,300 kPa with the conventional charge) and significantly reduced the perforation friction (2,600 kPa at 2.5 cu m/min versus 6,700 kPa). The calculated number of open perforations is 5.2 for the regular charge (19.3% efficiency) and 7.4 for the new charge (27.4%).

Since step-rate test interpretation involves iterative matching of a model to the field data, the results are dependent on the quality of data gathered and subject to a certain amount of engineering judgment. However, consistent application of the same methodology has confirmed similar results across multiple pairs of wells in the region and elsewhere.

Treating power analysis

To further examine the impact of perforating with the new charges on hydraulic fracture treatment, an analysis has been conducted of treating power requirements against treating rate in the Cadomin formation.

Figure 7 shows a crossplot of treating power against the rate for the 15 wells studied. Those wells perforated with the new charge clearly fall on the low side of the overall data set, confirming our hypothesis that cleaner tunnels allow treatment at reduced pressure loss, and therefore use less hydraulic horsepower.

Furthermore, the average breakdown pressure gradient was reduced by 41% (from 14.3 kPa/m for wells perforated with conventional charges to 8.4 kPa/m for wells perforated with the new charges) and the average treating gradient was reduced by 19% (from 16.2 kPa/m with conventional charges to 13.2 kPa/m with new charges).

These benefits translate directly into value for the operator, who is able to reduce pumping costs for a given treatment.

Conclusions

Perforating with the recently introduced reactive perforators significantly reduces near-wellbore pressure effects observed during fracture stimulation.

The difference between measured formation breakdown gradient and fracture gradient (which affects the surface pressure required to initiate the fracture) is significantly reduced. This minimizes the risk of being unable to initiate the fracture due to surface equipment pressure limitations, reduces the stress placed on surface equipment operating at high pressure (lower maintenance costs), and may allow operators to mobilize fewer hydraulic horsepower to location (lower operational costs).

Near-wellbore pressure losses during treatment (also known as tortuosity) are reduced to negligible levels. In combination with greater open area to flow as a result of higher perforating efficiency, this facilitates placing the fracture treatment as designed and reduces the risk of screen-out. The increased number of open perforations in contact with the fracture should also lead to improved productivity.

The benefits of increased perforation efficiency (holes open and taking fluid) and predictable pressure losses are particularly significant where limited-entry perforating is used as the diversion technique for simultaneously stimulating multiple zones.

The ability to place a very high percentage of fractures as designed – and to apply more aggressive fracture designs once sufficient comfort has been gained with the new system – leads to greater overall well productivity.

Further work is ongoing to evaluate the efficacy of the new perforating charge to a wider range of lithologies, reservoir properties, and pressure/stress regimes. The results of this work will be reported in a future paper.

Acknowledgements: The authors wish to thank Devon Canada, Weatherford Canada Partnership and GEODynamics for their assistance and support with this paper.

This paper was originally presented as SPE 116226 at the 2008 SPE Annual Technical Conference and Exhibition, Denver, Colo., 21–24 September 2008.

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