What industry leaders expect in 2011

Amid uncertainty in the Gulf and an onshore renaissance in the shales, World Oil’s editorial advisors offer their predictions and advice for the year ahead.

Edited by David Michael Cohen, Managing Editor

Things were beginning to look up again for the oil and gas industry. The economy was recovering, credit had loosened up, and the price of oil was in the healthy—and, just as important, stable—range of $70–80/bbl. In the US, the Obama administration’s move to open up OCS leasing had even suggested the possibility of cooperation with an industry that had initially been uneasy about his early cap-and-trade efforts and focus on “green” jobs.

Then, of course, on April 20 the industry’s renewed sense of stability sank along with the Deepwater Horizon. With the Macondo well disaster came a six-month deepwater drilling moratorium, demanding new licensing and drilling requirements, and a 180° public image reversal of fortunes from the “Drill, baby, drill!” high point of two years ago. Not surprisingly, the uncertainty in the US Gulf of Mexico is a major focus of our industry leaders in the pages that follow: What are the new regulatory requirements? How will they affect investment decisions and hydrocarbon supply for the US? What is industry doing—and what must we still do—to prevent another offshore disaster of this magnitude and regain public trust?

Other topics addressed by our industry leaders include the evolution of the booming shale gas sector into liquids-rich plays and international arenas, implications of the Republican takeover of the US House of Representatives, and the technology developments that will drive the exploration and production of increasingly challenging reserves next year and in years to come.  

Challenges and solutions for 2011 and beyond

Dr. William J. Pike, Managing Consultant, NISC, an IBM Company; Contractor to National Energy Technology Laboratory; and Chairman, World Oil Editorial Advisory Board

I often wonder what my father would think of the oil and gas industry today. He entered the industry as a newly graduated petroleum engineer in 1941, working for Gulf Oil. Over his career, he was involved in quite a bit of technology development. In 1962, he was instrumental in installing what may have been the first intelligent field monitoring system. The system ran on a huge, tube-driven analog computer that, if memory serves me, was about the size of a small bus. It was not sophisticated by today’s standards, measuring only reciprocating equipment conditions and vessel fluid levels. Still, it was a revolution at the time. Dad eventually entered senior management and became mired in mostly nontechnical issues. Still, he monitored the development of new technologies avidly, believing that new technology was the solution to increased oil and gas production. That has not changed since 1941. In fact, it is more important today than ever as the resource base we must exploit becomes more and more unconventional.

The US Department of Energy’s Energy Information Agency estimates that the country’s oil and gas consumption will rise steadily over the next 25 years, retaining its approximate 60% share of global energy demand through 2035. Supplying the oil and gas to meet that demand entails a number of challenges for our industry. These challenges can be categorized based on the four types of resources we will have to develop, or further develop, to meet that demand. These are mature, unconventional, ultra-deepwater and Arctic resources, each of which comes with its own set of challenges.

Mature assets. To date, the global petroleum industry has produced about a trillion barrels of oil. There is no figure for total natural gas produced because, for a good deal of our history, we either used gas for in-field fuel or flared it.

While we have made remarkable progress in improving recovery factors, globally they still average less than 30% (being generous) of original oil in place. Doubling the global recovery factor would result in an additional one trillion barrels of recoverable reserves. That goal must be part of the global strategy to meet increasing demand.

Thankfully, industry is committed to this goal and is actively working on technologies such as enhanced flooding techniques, improved fracturing technologies and better reservoir imaging and modeling.

Unconventional resources. Less than 10 years ago, there were plans and/or permits to build more than 60 LNG import terminals in the United States. This year there are none. In fact, the US may become a net exporter of gas in 2011. This remarkable reversal of fortune is due to development of the country’s rich unconventional gas resource base, especially the massive shale gas resource.

Developing technologies, particularly huge, multistage fracturing programs, have made the increase in production and reserves possible. However, gas remains, primarily, a regional resource. The challenge in unconventional gas is, therefore, to transfer the technologies developed in the US shale gas plays to other gas-rich regions of the world.

Unconventional oil resources must be developed also. As we all know, heavy oil deposits, oil sands and oil shales hold vast quantities of hydrocarbons. Promising new in situ reservoir processing technologies—some already well-established, such as steam-assisted gravity drainage (SAGD) for oil sands—will eventually eliminate the need to mine these resources and process them on the surface, leading to greatly reduced recovery costs and better environmental stewardship. As with unconventional gas, it is imperative that these technologies be perfected and transferred to regions rich in unconventional oil resources around the globe.

Ultra-deepwater resources. A number of challenges exist in the development of ultra-deepwater resources, not the least of which is the aftermath of the Macondo blowout and the consequent tidal wave of regulations. This topic is addressed by some of my colleagues in the columns that follow this one. On the technical side, numerous challenges exist, among them access to, and maintenance of, subsea equipment; additional development of subsea processing; subsea power supply; hydrate prevention and mitigation; and further development of HPHT technologies.

Both industry and governments are funding research programs to find solutions to these challenges, but substantial progress must still be made if we are going to operate safely and efficiently in waters up to 15,000 ft deep.

Arctic oil and gas. Tapping the resources of the far north is a bit more problematic. The infrastructure is fragile, and access is seasonally limited. The resource spans offshore and onshore areas, including some of the most environmentally sensitive and politically contentious regions in the world. In the US, for example, development of the vast Arctic National Wildlife Reserve’s considerable hydrocarbon resources is prohibited under the 1980 law that created the refuge.

The environmental, public perception and political factors stalling development of these resources must be addressed as soon as possible by the industry. To this end, we can point to considerable progress in reducing the footprint of our operations in Arctic areas, such as advances in extended-reach drilling, but further progress must still be made.

Overarching technologies. In addition to renewing our commitment to develop the four resource types above, we can make great progress in our mission to meet increasing global demand for hydrocarbons by renewing our commitment to two exceptionally important overarching technologies: intelligent operations and nanotechnologies.

Depending on whom you ask, our path to intelligent operations has been either fairly rapid or painfully slow. Nonetheless, we are on the verge of implementation of intelligent operations in a number of areas. Once this integration of oilfield disciplines is taken from the field level to companywide—and then industrywide—deployment, the industry will experience a paradigm shift in efficiency and improvement in recovery factors.

To reach industrywide implementation of intelligent operations, however, will require abandonment of the proprietary information mentality that has characterized the industry since its inception. While no practical E&P professional could reasonably maintain that proprietary information is a thing of the past for oil and gas companies, much of what is considered proprietary today could be carefully shared to the benefit of the entire industry. Movement toward that goal should be an industry priority in 2011.

Finally, there is nanotechnology, which has so many applications in our industry that it would take several pages to list them all. From materials strengthening to in situ reservoir monitoring, to improved conductivity and so on, nanotechnology may be the key that opens the door to more previously “unproducible” oil and gas reserves than any other. The R&D occurring in nanotechnology is impressive and large scale. The industry must, and will, renew its commitment to the rapid development of this important technology in 2011.

Our renewed commitment to development of technologies to exploit mature, unconventional, ultra-deepwater and Arctic assets, in addition to developing intelligent operations and nanotechnologies, is imperative for our industry in 2011 and every year thereafter.

Dr. William J. Pike has 43 years’ experience in the upstream oil and gas industry and serves as Chairman of the World Oil Editorial Advisory Board. He is currently a consultant within NISC, an IBM company, and works under contract in the National Energy Technology Laboratory (NETL), a division of the US Department of Energy. His role includes analyzing and supporting NETL’s numerous R&D projects in upstream and carbon sequestration technology. Prior to joining NISC, Dr. Pike was Editor in Chief and Editorial Director for Hart Energy Publishing’s E&P and Editor of the Journal of Petroleum Technology. Dr. Pike holds a PhD from the University of Aberdeen. He has contributed to several books on oil and gas technology and energy economics and has authored technical papers on offshore drilling and production.

Year in review and preview for US oilpatch

David Pursell, Managing Director and Head of Macro Research, Tudor, Pickering, Holt & Co.

Broadly speaking: Oil good, natural gas bad. As gas prices hovered around $4.40/Mcf in 2010, crude oil prices averaged $88/bbl, higher than many expected as global economic recovery took hold and non-OPEC supply growth remained tepid. Even though global petroleum inventories have been ample, the market seemed to look ahead for continued economic recovery. US natural gas is a different story, which can be summed up as “Too much drilling equals too much gas.” However, gas-directed drilling remained firm in the teeth of $4/Mcf gas, driven mainly by determination to hold acreage in the emerging shale plays.

The Macondo blowout was as close to a black swan event as we had in 2010: totally unpredictable, but with enormous impacts (more on that below). Although some questions remain, 2010 was spent capping the well and trying to figure out what happened. A shout out to the US Coast Guard for keeping its investigation and hearings apolitical, with a razor focus on finding out what happened. To summarize the findings so far, poor well design and execution, with a healthy dose of bad luck, caused a failed cement barrier and a BOP that did not function—ending in 11 fatalities, about 4 million bbl of oil spilled and a huge black eye for the industry.

LNG was a non-factor for the US in 2010, with imports of only about
1 Bcfd. We are still waiting for that tsunami to hit the US, and we are not holding our breath.

QEII, which used to be just the name of a steamship, is now every pundit’s favorite acronym for the latest Federal Reserve policy. “Quantitative easing” is a fancy term for encouraging inflation, weakening the US dollar and putting upward pressure on oil prices.

Looking ahead to 2011, the oil and gas market looks a lot like in 2010: Oil is good, natural gas not so much. Crude oil prices should remain firm as global demand growth continues to have some traction and quantitative easing continues to push oil prices higher. For natural gas prices, it’s like the Fram oil filter guy used to say, “You can pay me now, or pay me later.” Bottom line: Until the rig count falls, production will keep growing and the North American gas market will remain oversupplied.

In the long term, we see a $6/Mcf gas price—but we can’t get there until the rig count slows. The drill-to-hold-acreage drive could start to slow in second-half 2011, which is good, because a drop of 150 rigs in the emerging shale plays (Eagle Ford, Haynesville, Marcellus) would be just the thing to balance the US market.

In the debate over hydraulic fracturing—front and center in 2010, especially in Pennsylvania and New York—new data from Pinnacle Technologies show conclusively what the industry already knew, that fracturing does not contaminate groundwater. That said, drilling operations are not without risk, and we expect industry, government and environmental groups to focus more on best practices in casing cementing and surface materials handling issues. However, the “debate” around fracturing should fade a bit in 2011.

QEIII—Really? No idea if additional quantitative easing will be required, but after QE, QEII and TARP, what is another trillion dollars among friends? Fed policy is to encourage inflation, and if QEII does not work, don’t be surprised if they go to the well one more time. This matters because further easing could be a significant driver in pushing oil prices above our $90/bbl long-term target while simultaneously weakening the dollar. More importantly, the Pursell family European vacation next summer may be cancelled due to a weak dollar. Myrtle Beach, here we come!

A big focus next year will be gauging the pace of the return to normalcy on the Gulf of Mexico shelf and deep water. The deepwater permit approval process will be slow during the first half, with only a few issued, and will accelerate during the second half as BOEMRE and industry agree on what needs to be addressed in the new permitting process.

Next year will also see the courts start to assign liability in the Macondo blowout. The difference between negligence and gross negligence will be hotly debated, as it has implications for how much of the cost BP can spread to partners and service providers. My firm maintains that the lion’s share of the liability rests on BP as the operator of the well. One aspect of the liability is the potential for the Macondo reservoir fluid to be a volatile (near critical point) oil. Volatile oils have a large portion of light ends (lots of evaporation), and the remainder is paraffin base (rapid bacterial degradation). So the actual shoreline damage and overall liability may end up being much less than initial forecasts suggested.

Yes, the midterm elections were a big deal. Political pundits suggest that the recent elections can be read as a stunning rebuke of Democratic policies—or simply “miscommunication of the message.” I believe it’s the former but, either way, game-changing energy legislation is unlikely before the 2012 presidential elections.

Did somebody say NGLs? E&P companies have been drilling gas plays with lots of natural gas liquids, which meaningfully improved the economics even amid low gas prices. Great idea, except that everyone is reacting to the same market forces and, as a result, NGL prices are suppressed as I write this article. There is a chance that NGL prices are further suppressed because the US ethane/propane markets are at risk of oversupply. Bold prediction: E&P companies will talk more about end uses for NGLs in 2011 than they have in the past 10 years, and maybe lower NGL prices will be a needed catalyst to lower the gas-directed rig count.

David Pursell is the Head of Macro Research at Tudor, Pickering, Holt & Co. Securities, and was one of the founding partners of Pickering Energy Partners Inc. Mr. Pursell is responsible for macro oil and gas strategy, which includes supply, demand and pricing outlooks. Mr. Pursell previously worked as Director of Upstream Research at Simmons & Company International, and in various production and reservoir engineering assignments at S.A. Holditch and Associates (now part of Schlumberger) in College Station, Texas, and at Arco Alaska in Anchorage. He holds BS and MS degrees in petroleum engineering from Texas A&M University.

Fallout in the Gulf from deepwater rules

William Donald (Donnie) Harris III, President and CEO, Forrest A. Garb & Associates Inc.

Our industry seems to be in a period of relative stability compared to previous years, probably due to the slowed worldwide economy and the tapering off of demand for new hydrocarbon reserves. However, in the US, new drilling restrictions in the Gulf of Mexico and elsewhere could have long-term impacts that are damaging to oil and gas interests.

One of the first things to happen following the oil spill and subsequent implementation of the drilling ban was lost jobs, not only in the offshore drilling sector, but also in the huge supporting infrastructure. This included support for all of the offshore rigs, local restaurants, hotels, grocery stores and the related trickle-down spending, since most offshore workers live locally and their lack of income decreased spending up and down the food chain. It was estimated by federal officials that 8,000–12,000 jobs were lost due to the moratorium on deepwater drilling alone. Additional jobs were undeniably lost due to the slowdown in shallow water drilling permitting (defined in the first version of the deepwater ban as less than 500 ft), which has itself been referred to as a de facto moratorium. Shallow-water operators have laid off, or put on unpaid leave, hundreds of workers since the oil spill. As offshore drilling ramps back up, the jobs will come back to the area; however, some businesses and communities will forever be changed.

The six-month deepwater drilling moratorium was lifted on Oct. 12, and toughened regulations were put in place. Anytime the government changes the ground rules, new uncertainties are introduced, and investors do not like uncertainty in drilling rules, tax structure or perceived liability. Exploration projects will require additional scrutiny before investment decisions are made. The overall effect will be to add costs and slow down investments in prospect drilling locations, increasing the time it takes to produce reserves to the market.

Furthermore, there is currently a slow response time on permit approval at all water depths. Until a number of permits are approved, there will remain uncertainty in the new regulations, and the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) is still working on developing additional rules and guidelines, leaving a question mark on future deepwater drilling requirements.

One of the new requirements is to add an extra sheer ram to the BOP stack, which should be able to cut through virtually anything. These rams may not be readily available and may be difficult to retrofit for every type of BOP stack, so that slows everything down. An additional requirement is that the operator must get certifications on the casing design and cementing procedures and have the BOPs tested and certified. While this unquestionably improves the safety of the well, there is uncertainty regarding the standards required for these certifications. Everyone is discussing deep water, but all offshore exploration and exploitation activities will be impacted.

Furthermore, overall drilling safety would likely have been improved just as much if existing rules had been correctly interpreted and enforced. Operators are not incentivized to cause disasters, but the aftershocks from the BP Macondo blowout will have everyone looking over their shoulders. The Gulf disaster also sets the stage for more regulations due to perceptions, not facts. Once unleashed, this drive toward more regulation could bleed over into other practices, such as fracturing and acidizing of wells.

The costs of new regulations are going to add expense to the whole E&P process, both in manpower and in equipment costs. More manpower will be spent on filings, especially on the oil spill response plans. Operators may have to put up more bonds than before in order to drill in the Gulf. Idle rigs could be moved overseas if drilling does not resume soon, and this will hinder companies’ future ability to economically explore for reserves in the Gulf.

But it’s not all bad news. On the positive side, the GOP majority in the US House of Representatives resulting from last month’s midterm election will help keep a lid on federal efforts to pass cap-and-trade legislation, frac fluid regulation and the end of certain tax deductions for our industry.

William Donald (Donnie) Harris III is CEO and President of Dallas-based Forrest A. Garb & Associates Inc., which he first joined as president in 1998. He is responsible for the firm’s daily operations and the supervision of engineering projects. Mr. Harris began his career with Arco Oil & Gas as a reservoir engineer. He holds a BS degree in petroleum engineering from Texas A&M University and an MBA from Southern Methodist University.

The impending P&A train wreck in the Gulf

Douglas C. Nester, COO, Prime Offshore LLC

Even though we can see the light, hear the horn and feel the rumble, many independents operating on the shelf seem to remain oblivious to the oncoming plugging and abandonment (P&A) train that is about to collide with the Gulf of Mexico. Approaching with ever increasing speed, this locomotive of liabilities is already causing financial havoc to some. The handling of abandonment liabilities will dominate much of the industry’s shelf operations for 2011 and, I believe, for the decade to come.

Historically, P&A liabilities were often viewed as future costs that could ultimately be deferred unto the next generation of managers or the next owner of the producing asset. With the GOM shelf now firmly matured to the point of assisted living, these once-distance costs are becoming today’s realities for many of its fields.

A P&A obligation is like death; you can try to delay it for as long as possible, but sooner or later it will occur. Looking at statistics from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), our industry has done a pretty good job of delaying the inevitable. At the beginning of 2010, there were 5,390 idle wells in the GOM. As evidence of our efficiency in futility, 775 of these wells are temporarily abandoned, which is a fivefold increase from the total temporarily abandoned as recently as 2005. In addition to wells, there are also 761 structures that need to be removed. Of these, 477 are idle and 153 are in fact located on expired leases.

This ever-increasing backlog of liabilities has not gone unnoticed by the US government, which estimates total decommissioning exposure for idle iron to be in the range of $1.4 billion to $3.5 billion. As a result, BOEMRE has issued new idle-iron policies that require current operators to conduct decommissioning activities in a very specific and timely manner. The notice to lessees (NTL) released on Sept. 15 by Interior Secretary Ken Salazar states that any well that has not been used during the past five years for exploration or production must be plugged, and associated production platforms and pipelines must be decommissioned if no longer involved with E&P activities. Operators have been reluctant to P&A wells that are on leases with active wells until required to do so by law, which previously was one year after their lease expires or production terminates. In many cases, this termination occurred several years after wells were idled. The government estimates that this new NTL will force the P&A of about 1,200 wells per year and the removal of 130 structures per year over the next three to five years.

Governmental guidance is not the only reason we will see an acceleration of P&A and decommissioning operations in the near future. As our industry continues to suffer under the weight of extended low gas prices, some shelf operators are now finding that their production and reserve values are no longer sufficient to support existing operating costs and book values.

Hurting the most are owners of old legacy projects where just a few producing wells are burdened with the P&A and decommissioning liabilities associated with all the idle iron remaining from when these assets were at their maximum production levels. In many cases, these assets have changed hands numerous times from the majors who originally developed them, to smaller and then even smaller independents as remaining reserve potential of these fields declined. There are many examples of blocks where idle wells now outnumber active wells by a factor of 10 to 1 and where there are more idle platforms and flowlines than those being used in production.

Companies will now be forced to adjust budgets, reserve reports and balance sheets to reflect these near-term P&A and decommissioning liabilities. Many companies will struggle with the realization that the true cost of these liabilities is far in excess of what they have historically recognized and reported. This will be particularly true for companies that use discounted present values for their booked P&A liabilities instead of estimates reflecting recent rates for barges, service and manpower. Complicating this even further is the likelihood that the high volume of decommissioning activity to be carried out in the next few years will increase the cost of services beyond today’s rates.

In an attempt to relieve themselves of these growing liabilities, some companies are desperately trying to divest of legacy projects that have a few years of strong cash flow remaining before any large abandonment investment is needed. The problem now occurring is that sophisticated buyers are not accepting the discounted P&A values presented in the sellers’ reserves reports. As a result, sellers’ expectations of asset worth based on net present values are significantly higher than what buyers are willing to pay. As a buyer, I can certainly attest to the existence of this difference and to the fact that many sellers are electing to keep this cash flow and hope that their P&A liabilities as currently booked are correct.

For many GOM operators, it will soon be time to pay the piper. For those who have properly prepared for their obligations, the increase in P&A operations will be just a project manager’s headache. For those who have not, the next few years will be a real financial struggle.

On the other hand, the increase in decommissioning activities will likely prove to be a real growth opportunity for existing offshore construction companies and new ones that will have to be created in order to fill the needs of operators. The expanding backlog of work will ultimately result in an increase in the number of people working in the Gulf of Mexico.

As this train prepares to pull into the station, we can once again ready ourselves for the one sure thing that operating in the Gulf of Mexico always brings, and that is change.

Douglas C. Nester, COO of Prime Offshore, is responsible for the company’s operations and new venture activities. He previously worked for Pennzoil, 3DX Technologies Inc. and, most recently, Devon Energy. Mr. Nester earned his BS degree in geology from Indiana University of Pennsylvania, and performed his graduate studies in geology at the University of Houston. He earned an MBA in finance from the University of St. Thomas in Houston.

Quantum change requires bold leadership

Robert E. Warren, Vice President of Industry and Government Affairs, Pride International Inc.

“If a man takes no thought about what is distant, he will find sorrow near at hand.” 
—Confucius, Chinese philosopher and reformer, 551–479 BC

Last year, as companies worked through a depressed business climate, I stated that, although there were too many dragons and not enough swords, the drilling industry would persevere through the downturn. As if recession conditions were not enough of a challenge coming into 2010, the Macondo well disaster and its aftermath brought much of the US offshore energy industry to a halt from April onward. While an angry public watched the spillcam pour images from the broken well into millions of living rooms for four months, the BOEMRE replaced the MMS, bringing enormous change to the way we conduct business.

With Macondo blowing at full force, the Obama administration shelved its previous plan to open up exploration on the Outer Continental Shelf after decades of closure—a move that in 2009 had been well-received by industry and by coastal states keen to develop their offshore oil and gas resources. In the absence of strong pro-development voices within the administration, a national crisis or $4/gallon gasoline, it may be years before the restricted areas are again considered for leasing and E&P activities.

Immediately following the blowout, an unprecedented coalition of industry, government, academics and US Coast Guard personnel commenced the Herculean task of killing the Macondo well. Early into the tragedy, it became apparent that the existing emergency response plan, available equipment, systems and technology were insufficient to overcome a well control crisis of this magnitude. Drilling technology had outpaced containment and spill response, and once the rig was destroyed, an armada of equipment and an army of industry personnel were required to overcome the most challenging wild well ever unleashed offshore.

Significant procedural and response shortcomings have been reported by media and official review, but there was a remarkable, sacrificial partnership forged across every sector of the energy space to achieve the solution at Macondo. Competition among organizations gave way to cooperation for a higher purpose, and the partnership continues as industry works at full throttle to implement solutions for preparedness and spill response.

We will adapt to the new regulatory requirements, and we will be a better and stronger industry. Unfortunately, energy operations and the support chain throughout the Gulf Coast may be irreversibly downsized. Another unfortunate consequence is that the US will find it more difficult to draw on domestic resources in the event of a national security crisis. “Too big (i.e., important) to fail” has not applied to the oil and gas business, and our critical GOM energy supply will likely decline rapidly. Be thinking about the 1973 crisis.

Outlook for 2011. While the moratorium for deepwater drilling has been lifted—and there was no official moratorium for shallow-water operations—the combined effect of restrictive new permitting requirements and new operating safety procedures under the BOEMRE has effectively reduced GOM drilling operations to a fraction of the pre-Macondo level. The result is that operators and contractors are actively reviewing foreign locations for investment and repositioning. Some floaters have departed, and others are under active review for mobilization to less restrictive waters. Older assets that may not pass muster under the new rules will leave the GOM or move to the closest stack site. Capable jackups, which could otherwise be working, will be idle while clients work through lengthy permit delays. Watch for more demobilizations there.

Land operations should increase as operators ramp up their US onshore business, although increased regulations are likely there as well. A concerted effort is ongoing among environmental groups for the reduction or complete cessation of hydraulic fracturing, essential to shale gas production. Fracing is regulated by the states, but the federal Environmental Protection Agency is currently investigating alleged groundwater contamination due to fracing under a congressional mandate, and its findings could potentially lead to federal fracing regulation.

Although multiple independent studies across the decades have repeatedly failed to find conclusive evidence linking fracing to groundwater contamination, there is still strong resistance to this key technology. Watch closely and support the American Petroleum Institute and the Independent Petroleum Association of America as they work hard to educate the public, Congress and regulators on this and other environmentally sensitive topics.

Countries with long-term development programs are destinations of choice for idle assets in the Gulf of Mexico, and in the classic win-win for them, those countries are working to take advantage of the available GOM rig inventory. Producers like Brazil will continue to tender projects where orphaned floaters and jackups could work for years. The price of crude may not significantly increase in the near term, but we will soon have lost strategic leverage from the once robust Gulf of Mexico supply chain. Floaters and jackups will not return to US waters nearly as quickly as they depart.

Initiatives for the new order. In recent speeches before audiences across the political spectrum, administration officials have clearly signaled that all effort will be made to bring “clean energy” to a much higher development level and utilization. But the two categories of energy—fossil and renewable—should not be developed in competition at the expense of one another. Nor should the development of either be impeded by severe regulatory requirements. There should be no adversaries here in the development of energy for the nation.

To this point, demonstrable environmental stewardship and sustainable employee safety must be driven to an ever-higher level. We have to actively engage critics of fossil fuel with the evidence of that effort through education and partnerships outside of the industry—including government and non-governmental organizations.

While oil and gas will long remain the engine of economic and societal development in the world, perception is reality in the absence of broad and transparent stewardship. That stewardship is very much there, but not sufficiently visible to a skeptical public. Confucius seems to have recognized the near-term/long-term dilemma we face, and the question is: Will we make the adjustments that satisfy both ends of that continuum?

Bob Warren is Vice President of Industry and Government Affairs for Pride International Inc., responsible for company interface with industry organizations, regulatory agencies and communities. He has worked in executive operational and corporate capacities at Pride, and serves on a number of industry boards and committees. Warren holds a BS degree in petroleum engineering from Texas Tech University and an MBA from the University of Texas at Austin.

Prospects to improve activity on UKCS

Alexander Kemp, Professor, University of Aberdeen

The year 2010 has been one of mixed fortunes for the UK Continental Shelf, with the positive features generally outweighing the negative ones. Wells drilled are often taken as a barometer of overall activity. By the end of the third quarter, the number of exploration wells spudded had exceeded the (low) total of 23 for the whole of 2009, and exploration drilling should end the year at around the yearly average for the last decade: 28. On the other hand, the number of appraisal wells spudded in 2010 has been running at levels slightly below those achieved in 2009, when 42 were drilled. Development well drilling has been proceeding at levels in line with those undertaken in 2009, when 130 were completed, but this number was far below those achieved over the last decade, when the annual average was 207 wells.

Some retrenchment of development activity occurred in 2009 as a consequence of the fall in price in 2008 and the effects of the wider financial crisis on the costs of obtaining finance. Nevertheless, development expenditures were around £4.8 billion, in line with those for 2008. By the end of 2010, around £5 billion is likely to have been spent. Operating expenditures were trimmed to around £4.7 billion in 2009, and they are likely to have continued at around this level in 2010. When exploration and appraisal expenditures are included, total expenditures in the UKCS could end up around £13 billion, somewhat above the 2009 level.

There were several highlights of 2010 with longer-term consequences. The decision by Total to proceed with development of the Laggan and Tormore gas fields in the West of Shetlands region is a key example. The full development plan involves the construction of two new pipelines of 143 km in length to the Sullom Voe terminal on the Shetland Islands. After processing there, the gas will be taken in another new 234-km pipeline to tie into the Frigg UK pipeline, after which the gas goes onward to the major onshore terminal at St. Fergus.

The scheme will not only secure the development of over 1 Tcf of gas from this frontier region, but also will facilitate the exploitation of further gas discoveries in an area whose development to date has been hampered by the absence of pipeline infrastructure. There is sufficient capacity in the planned new pipelines to accommodate gas from several other undeveloped fields in the region.

The whole project will be very expensive, with total investment costs estimated at £2.5 billion. The UK government has acknowledged the particular difficulties surrounding the economic viability of gas fields located far from existing infrastructure and has introduced a substantial field allowance against the Supplementary Charge. However, it will not be available to gas fields in the region that are less than 60 km from the main infrastructure.

The past year witnessed several new discoveries or positive appraisals of existing ones. Notable examples are in the Catcher area and the Golden Eagle complex. Both offer the prospect of future developments with reserves far above the UK average field size, which is now just over 20 million boe.

As a consequence of past discoveries (including less recent ones), the year 2011 promises to see an increase in development activity over 2010 levels. The current oil price in excess of $80 and the growing expectation that this level is likely to be maintained add weight to this view. Accordingly, field investment could be over £6 billion next year, and 2012 should see an even higher figure combining the continuation of large 2011 investments and commencement of new ones.

It has to be acknowledged, of course, that production continues to decline in the UKCS from the peak reached in 1999. But the activity for the oil and gas cluster is being maintained by the development of high-cost new fields, the very substantial investment in incremental projects in mature fields, and the refurbishment and extension of the infrastructure.

The Macondo well incident in the Gulf of Mexico has had some repercussions for the UKCS. The industry itself took the initiative and set up the Oil Spill Prevention and Response Advisory Group (OSPRAG), which has been very active in examining the processes relating to well control and the various measures that could be taken to prevent oil from leaking into the environment. An Indemnity and Insurance Review Group (IIRG) was also established by the industry to examine the potential remediation and compensation costs of spills. The work of these groups continues. A third group, the Oil Spill Response Group (OSRG), has been examining the oil spill response capability of the industry.

A fourth group, the European Issues and Global Liaison Sub-Group, has been responding to proposals from the EU to introduce a deepwater drilling moratorium or enhance the safety regulations relating to offshore drilling. Both the industry and the UK government have confidence in the safety regime established after the Cullen report in response to the Piper Alpha disaster in 1988, and feel that there is no case to restrict deepwater drilling in the UKCS. However, some enhancement to the current regime may be expected when the various studies are completed.

Third-party access to infrastructure is a major factor in the development economics of the typically small fields in the UKCS. Up to the present, the terms of such access have been determined in negotiations between asset owners and users. Often these are fraught and prolonged. An Infrastructure Code of Practice exists, but problems have remained. Earlier in 2010, a request was made to the Department of Energy and Climate Change by a potential user to make a tariff determination in a case where agreement had not been reached. At the time of this writing, the government’s determination is eagerly awaited. This is important because, although it will apply to only one case, the principles used may well influence negotiations in other cases.

Political events, sometimes external, can mightily affect activity in the UKCS. Currently, the international sanctions against Iran may stifle production from the North Sea. Rhum Field is a 50/50 joint venture between BP and the National Iranian Oil Company. At the time of this writing, BP was taking steps to suspend production from that field to comply with the latest EU sanctions against Iran. The repercussions are more serious than the postponement of the not-insignificant production for an uncertain period and the associated startup costs, because of the knock-on effects for Bruce Field, which receives the gas from Rhum.

One indicator of investor interest in the UKCS is the response to the invitations made in licensing rounds. In October, the offers made in the 26th Round were announced. A total of 268 exploration blocks were awarded with a further 99 still being considered. This can be regarded as a substantial number by historical standards. Most blocks have “drill or drop” conditions attached to them, with a further dozen having “firm well” drilling obligations. The majority of the blocks have been offered to medium and smaller-sized players, though some have been taken up by the majors.

When all the developing events and other information are added together, the UKCS is likely to experience a reasonably high level of activity in 2011 with further growth in 2012.

Alexander G. Kemp is the Schlumberger Professor of Petroleum Economics at the University of Aberdeen. He previously worked for Shell, the University of Strathclyde and the University of Nairobi. For many years, Professor Kemp has specialized in petroleum economics research, with emphasis on licensing and taxation. He also is Director of Aberdeen University Petroleum and Economic Consultants.

Great expectations, risks for 112th Congress

Burt Adams, President & CEO, OGRS LLC, and Chairman, National Ocean Industries Association

More than a month after the US midterm elections, the dust has settled, but the full ramifications of the dramatic shift in Congress—particularly for offshore energy development—have yet to be determined. It appears that the new Republican majority in the House of Representatives will support an “all of the above” energy policy to increase energy security and reliability. There are indications from President Barack Obama, too, that increased natural gas drilling may be proffered as an area where the two sides can find common ground. This makes sense to us in the oil and gas arena because any balanced multifaceted energy strategy has to include increased production of oil and gas in the Outer Continental Shelf.

The first question facing the new Congress and all Americans is whether it is safe to proceed with expanded oil and gas exploration in the wake of the Macondo well accident. The answer is a resounding yes!

First, any accident is one too many, and we still mourn the tragic loss of life on April 20, 2010. It is difficult to parse a bright spot from this dark day, but our industry has made a tremendous effort to take responsibility for ensuring a safe and secure offshore operating environment.

The Macondo well accident has sharpened our focus on safety. From the company parking lot to our rigs and platforms, every one of our managers, CEOs and employees has been reminded that the No. 1 priority is safety.

Immediately following the incident, industry cooperated fully with federal regulators in their inspections and suggested additional safety measures. Industry also strongly recommitted itself to existing safeguards. As the details surrounding the blowout, fire and spill become better understood, we are more than willing to work closely with those regulators to make changes in procedures and practice where necessary.

The new Congress has a critical role to play in this arena, too. Republican House leaders have indicated that reinvigorated oversight is their top priority. Congress can and should work with industry and regulators to hone the federal response to the accident to a sharp point that will specifically address the cause of the accident, rather than promote a cleaver approach, indiscriminately hacking a path to unnecessary new standards or regulations.

Any proposed regulatory scheme should not hamper our efforts to safely produce homegrown energy and jobs, and therefore must involve companies of all sizes, from the family-run enterprises to the major international corporations.

Regulators have been accused of being too “cozy” with industry, and vice versa. Despite the alleged failures of the past in this area, I believe a cooperative professional relationship that allows industry to determine the best way to achieve safety measures is not cozy. Federal regulators must ensure that safety is promoted and the environment is protected, but they cannot do this by mandating proposals through e-mails and proclamations without communication with all stakeholders, particularly industry.

Adherence to ethical standards by both industry and the federal government does not mean no contact. Regulators and industry cannot learn from one another without open communication. Perhaps such communication would have prevented the costly deepwater drilling moratorium, the slowdown of drilling permits we refer to as the “permitorium,” and related rounds of litigation.

Although the deepwater moratorium was lifted on Oct. 12, its impacts still linger. As mentioned above, the “permitorium” in both deep and shallow water persists. In fact, a month after the moratorium was lifted, not a single new deepwater drilling permit had been approved by BOEMRE. Because of new, stricter drilling regulatory requirements on industry and the confusion these caused within BOEMRE itself, the rate of drilling permit approvals is predicted to be a small fraction of what it was before the Macondo incident. At least four rigs have left the Gulf of Mexico for work in other regions of the world, taking hundreds of jobs with them. Other drilling and support companies idled by the moratorium waited it out and kept employees busy with maintenance and even spill response and cleanup work. But there is only so much maintenance work to be done, and with less and less oil being found, cleanup work is winding down. As for future impacts, it appears the US will lose 18–24 months of momentum in developing deepwater resources due to the combined impacts of the deepwater moratorium and “permitorium.”

The industry and its trade associations wasted no time in joining forces in response to the Macondo accident. Joint industry task forces, established by the member companies of the National Ocean Industries Association, American Petroleum Institute, International Association of Drilling Contractors, Independent Petroleum Association of America and US Oil and Gas Association, have produced reports on the effectiveness of current subsea spill containment and surface spill response capabilities. The resultant recommendations will involve new investment, new technology and new expense, and our industry stands ready and willing to contribute these resources with the goal of ever-safer offshore operations.

This brings up another issue that the new Congress will undoubtedly consider: new or increased taxes and fees. Our industry has paid and will continue to pay its share of taxes, fees and royalties. About $75 billion has been paid in royalties and rents over the years, and as long as energy development is allowed to continue, billions of dollars will be paid in the future. A new Congress should be  hesitant to add additional taxes and fees that will eventually lead to fewer jobs, less domestic energy and higher energy costs.

The 112th Congress comes in with great expectations and even greater challenges. The offshore industry stands ready to work with them so that we may all share in the common goal of domestic energy security, home-grown jobs, safe operations and a clean environment.

Burt A. Adams is President and CEO of OGRS LLC in Morgan City, Louisiana, returning to the position he held at that company, then called Oil & Gas Rental Services Inc., for 10 years before it was purchased by Allis-Chalmers Energy. He has also served as Vice-Chairman, President and COO of Allis-Chalmers. Mr. Adams earned a BS degree in civil engineering from Tulane University in 1983 and an MBA from Harvard University in 1988. He serves on the board of ATP Oil & Gas Corp., the Offshore Energy Center (where he is Past Chairman) and the Ocean Star Museum in Galveston, Texas. He is the current Chairman of the National Ocean Industries Association and a member of the Board of Advisors of Tulane University School of Science and Engineering.

The adaptive well factory

Dr. D. Nathan Meehan, Senior Executive Advisor, Baker Hughes

The transition in the drilling industry from segmented operations to fully integrated operations can potentially allow operators to drill hundreds or even thousands of roughly similar wells at costs that will decline over time. Factory costs related to scale often see performance improvements that allow 10–20% unit cost reductions as volumes double. Conversely, the highly variable costs associated with manufacturing many different items often see unit cost increases of over 20% with each doubling of variety.

Operators in unconventional gas and oil reservoirs are keen on lowering costs by rapidly identifying drilling and completion approaches that are nearly optimal, given the massive capital costs associated with developing these reservoirs. This has been true of essentially every large drilling campaign.

The difference today is that the tools used to understand unconventional reservoirs have changed; the wells are primarily horizontal with many multistage hydraulic fracture treatments, and new petrophysical and geomechanical approaches are required. Recent technological advances will be essential to leverage the scale of unconventional drilling activity while addressing the wide variety of reservoirs encountered.

Advanced directional drilling and LWD technologies are now commonplace. The quality of data gathered during drilling allows operators to geosteer in thin zones with complex structures and evaluate the formations in near-real time. Completion practices have changed dramatically over the last decade as a result of the focus on very long horizontal and multilateral wells in unconventional reservoirs. Dozens of separate frac treatments in wells with either plug-and-perf or openhole-packer-and-sleeve methods are routinely capable of generating significant hydrocarbon rates from rocks that until recently were not considered reservoirs.

One new trick the industry has learned in the last decade has been to integrate geomechanics into our understanding of the reservoir. Along with geology, geophysics, petrophysics, reservoir and production engineering, geomechanics has become an essential tool in understanding where and how to drill, complete and operate wells more effectively.

My first encounter with geomechanics was as a graduate student studying hydraulic fracture orientation and analyzing wellbore breakouts. While I was only interested in the fracture azimuth, I learned just how valuable image logs could be for understanding wellbore issues—particularly wellbore stability in directional wells—and, later, for understanding critically stressed fractures.

One of the many contributions of geomechanics is particularly relevant for understanding the performance of unconventional gas and oil reservoirs. Critically stressed fractures can be major contributors to production in shale reservoirs. Flaws that are nearly impermeable otherwise but are oriented in certain directions with respect to the stress fields may slip by tiny amounts in shear and result in substantial local increases in flow capacity. Conventional hydraulic fracturing models are dominated by tensile failure. These fractures alone do not explain the performance of successful shale wells nor the substantial microseismicity observed while stimulating such wells.

Geomechanical models help explain and predict the orientations, frequency and abundance of critically stressed fractures and enable operators to optimize stimulation designs and well spacing. Mineralogical analyses of shale reservoirs using pulsed neutron and other geochemical tools allow us to understand details of the depositional environment, identify shale lithofacies, make realistic estimates of effective porosity, identify and compute total organic carbon, and improve the placement of laterals and stimulation designs. Ultimately, reservoir models must be able to more accurately predict drainage areas in order to optimize interwell spacing so the resource can be drained without overdrilling.

Hydraulic fracturing has changed radically from a few decades past where the standard jobs involved high concentrations of crosslinked gels with proppant concentrations of 8 ppg or greater. Many applications have seen success using “water fracs” that consist of vastly greater quantities of lower-concentration uncrosslinked gels with low sand concentrations (on the order of 0.5–1 ppg) pumped at dramatically higher rates. Geomechanical models are highly predictive of where such treatments will be most successful.

However, water fracs lead to accelerated wear and tear on pressure pumping equipment. High levels of activity and increased repair and maintenance costs have resulted in higher prices for pressure pumping services. Innovative ways to drill and complete large numbers of wells and frac stages to optimally drain shale reservoirs hold the promise of significantly lowering the total cost per barrel of oil equivalent in large-scale drilling campaigns.

Many operators have puzzled over the high variability from location to location in unconventional reservoirs. In many cases, these variations cannot be easily predicted from conventional logs or even cores. Because many large areas show similar distributions of well performance based on estimated ultimate recovery and little spatial correlation, operators may use statistical methods to estimate the results from further development drilling and get good agreement in the aggregate. For a given well that has the appropriate measurements, we can routinely simulate and match well performances using reservoir simulators and specialized type curves designed for the types of fractures we think are created. Such models rely on accurate porosity estimates and reservoir descriptions.

When the industry doesn’t make such measurements, it is impossible to fully understand the spatial variability of key reservoir variables or calculate them from measurements. In these cases, we cannot predict or explain the variability of well performance for similarly completed wells. This will lead to a sub-optimal approach to the drilling and completion of hundreds and potentially thousands of wells.

The optimal drilling factory will need to incorporate new technology and different reservoir-based views of unconventional reservoirs and integrate them into development plans “on the fly” to create the greatest value. If product prices were significantly higher, sub-optimal development would be more forgiving. The exciting challenges posed by unconventional reservoirs are some of the most important things we must “get right.”

Advanced geomechanical modeling has greatly improved our understanding of shale behavior. In the early days of horizontal wells, there were similar questions about well placement, optimal lengths and incremental recoveries. As the industry’s experience grows, operators who invest in understanding these reservoirs will inevitably outperform the rest.

Dr. D. Nathan Meehan is Senior Executive Advisor for Baker Hughes Inc., where he supports executive management in the areas of reservoir technology, emerging technologies and business trends in E&P. He was previously the founder of CMG Petroleum Consulting Ltd.; Vice President of Engineering for Occidental Petroleum; and General Manager of Exploration and Production for Union Pacific Resources. He holds a BSc in physics from Georgia Tech, an MSc in petroleum engineering from the University of Oklahoma and a PhD in petroleum engineering from Stanford University. His reservoir blog is featured on the Baker Hughes website at http://blogs.bakerhughes.com/reservoir/.

The limits of forecasting in oil and gas

Bill Coates, Vice President of Sales and Marketing, Schlumberger, and Chairman, Petroleum Equipment Suppliers Association

I think it would be fair to say that our predictions for 2010 were wrong.

Coming off the back of the economic collapse of 2008–2009, the pace and stability of the recovery dominated the headlines and made “uncertainty” part of the vernacular. Our industry, often in the headlines, dominated the news cycle in the second and third quarters of 2010. Unfortunately, the Deepwater Horizon incident, with the tragic loss of 11 lives, has put the industry on the defensive. We now face the very difficult job of regaining the public trust, and meanwhile a huge question mark hangs over the Outer Continental Shelf market in 2011.

North America was the story of 2010. While the Gulf of Mexico grabbed the headlines, strong activity in the US and Canadian onshore basins was responsible for most of the growth in our global industry. A sustained imbalance of the value of the oil versus gas has created an important and lasting shift in the US and Canadian markets, with the potential to remove the crushing volatility that has plagued the North American land market for many years. The importance of the shift to onshore drilling for oil cannot be underestimated.

Internationally, it has been a year of fits and starts. Continued uncertainty around the large integrated projects in northern Mexico affected the Latin America balance of activity in the second half of 2010. The slowdown in Mexico was offset to some degree by increasing land activity in other international arenas as operators chased a broad group of projects from conventional oil in the Middle East to coal seam and shale gas in Europe, Asia and Australia.

Pricing for products and services, which rebounded strongly in certain sectors—like pressure pumping in North America—continued to have slow and unsteady improvement in most international markets.

Deep water, a sector of the market that was slated to provide significant growth, suffered the effects of the drilling moratorium in the US Gulf of Mexico, mixed exploration success in the Eastern hemisphere, and general inefficiencies due to certifications and inspections stemming from the loss of the Deepwater Horizon. The one unqualified positive, of course, is the continued growth of activity in Brazil. Petrobras, following on the largest share offering in history, will invest in new areas like Tupi, but will also pursue further development of the classic plays of the Santos and Campos Basins as they continue to ramp up activity.

It would be easy to forecast “much of the same” going into 2011. But with the economy uncertain and the lingering effects of the Gulf of Mexico spill impacting the offshore sector, reality is slightly more nuanced. As I write this, the bailout of Ireland by the International Monetary Fund and the European Union is the latest threat to financial and fiscal stability. On the positive side, news on the health of the US economy and that of the BRIC (Brazil, Russia, India and China) countries seems to be more positive than most projections. As a result, estimates of demand growth for oil are in excess of 1.5 million bpd for 2010 and oil prices have hovered between $75 and $85/bbl for most of the year.

Simply stated, barring a widespread double-dip recession, we can expect oil-related activity to be on a firm footing in 2011.

Natural gas, especially in the North American market, is a much riskier proposition. Any surprise will likely be positive, as most people have already factored low prices and declining gas-directed drilling activity into their plans.

We hear it often, but it bears repeating: Oil and gas is a challenging and technical business. When we close the books on 2011, our performance will largely be judged by the industry’s positive response to a myriad of sensitive issues, including hydraulic fracturing and the surrounding issues related to water; the restart of deepwater drilling; and the expansion of enhanced recovery projects that with luck and planning will allow us to continue to bring energy that is affordable and environmentally sensitive to the public.

Bill Coates is the current Chairman of the Petroleum Equipment Suppliers Association, and Vice President of Sales and Marketing for Schlumberger. Before assuming that position in January 2010, he served as the company’s President for North America. He previously held positions at Schlumberger as GeoMarket Manager of Schlumberger Oilfield Services’ Gulf of Mexico operations, IT and E-Commerce Coordinator for Oilfield Services and Manager of the Austin Product Center. Mr. Coates began his career with Schlumberger in 1988 as a Wireline Field Engineer at Houston Offshore. He holds a degree in mechanical engineering from Virginia Tech University.