EU Proposes New Rules to Boost Offshore Drilling Safety

The European Union's executive body Thursday proposed new rules to increase the safety of oil and gas offshore drilling, in a move aimed at preventing accidents in EU waters similar to the Gulf of Mexico oil spill last year.

"The idea is to avoid accidents here, but if there is environmental damage, the idea is that the damage should be compensated for" and cleaned up, Guenther Oettinger, European Commissioner for energy, said during a press conference to present the plan.

According to the new proposal--which will have to be backed by the European Parliament and EU governments before becoming law--companies will have to submit to national authorities a plan on how they are ensuring safety for personnel and preventing environmental hazards.

They will also have to show that they would be ready to react to any emergency and have the necessary financial and technical capabilities to clean up in case of a major accident.

"If there is a spill, the operators are responsible," Oettinger said.

The EU has more than 1,000 oil and gas platforms, mostly in the North Sea, but 13 countries have issued licenses, and the commission is keen to harmonize legislation to the best and safest standard.

The provisions would apply to all platforms in EU waters because they would stretch up to 370 kilometers from the coast, and are widely based on the laws regulating the sector in the U.K., the European country with the highest number of offshore platforms, an EU official explained.

Copyright (c) 2011 Dow Jones & Company, Inc.

O&G Producers Studying Europe's Shale Gas Potential

While Poland has taken center stage in European shale gas exploration, oil and gas producers also are exploring for potential shale gas reserves in other European countries.

"Unconventional gas volumes in Europe have the potential to stabilize domestic supplies in the face of declining conventional production, and in doing so could reduce dependencies and help diversify the energy mix," said Maximilian Kuhn and Frank Umbach, authors of a study from the European Centre for Energy and Resource Security (EUCERS).

In the report, Strategic Perspectives of Unconventional Gas: A Game Changer with Implication for the EU's Energy Security, the authors noted that European shale gas could help break Europe's dependence on gas imports from Russia and the Middle East.

Besides Poland, which is estimated to have 187 Tcf of recoverable shale gas resources, and France, where a ban on hydraulic fracturing has resulted in some shale exploration permits being cancelled, concessions for shale gas test drilling have been granted in the Netherlands, Germany, UK, Sweden, Hungary, Switzerland, and Ukraine, according to a U.S. Energy information Administration (EIA) report on global shale gas resources released in April.

Producers also are exploring for shale gas in other European countries. In Spain, Realm Energy International Corporation will explore for shale gas in the two six-year permits the company was awarded earlier this year. The permits cover 212,099 acres in the Cantabrian Basin of Northern Spain.

Realm believes the shales in all concessions are thermally mature and may be prospective for natural gas production. Initial analysis of existing well logs indicates that primary targets are likely to be Eocene, Cretaceous and Carboniferous shales at depths ranging from 6,000-11,000 feet.

According to media reports, Basque Regional Premier Patxi Lopez said last week that 13 unconventional gas holdings of 180 Bcm have been found in the Gran Enara field, located in the Alva province in Basque Country.

Chevron reported earlier this year that it is exploring Eastern Europe's shale gas potential in Romania and Bulgaria. In Romania, the company began a seismic acquisition program in August and, over the next year, will continue to progress technical work as it evaluates this opportunity. In Bulgaria, the company plans to begin seismic acquisition next year.

LNG Energy is also exploring for shale gas in northwestern Bulgaria. The company in late August reported it had entered an agreement to drill and test an exploratory well targeting the Middle Jurassic Etropole Shale.

The Czech Republic's Environment Ministry said in August it planned to commission a survey to determine shale gas levels, and British companies Cuadrilla and Basgas have submitted applications to start researching supplies in the coming months, according to a report by the Prague Post.

Swedish gas exploration company Gripen Gas AB will explore for unconventional shale gas in the organic rich Alum shale formation on five exploration licenses totaling 186 square kilometers on Oland in Kalmar County, southern Sweden. The company was awarded the five licenses in July.

Gripen is planning to start some shale drilling activities soon, according to a spokesperson with the Mining Inspectorate of Sweden. Gripen and a second company, Energigas i Östergötland AB, have exploration permits for shale exploration in Sweden at this time.

Gripen Chairman Torgny Berglund said the company's preliminary studies show that the Alum Shale could yield sufficient gas to generate power with the added upside of stratigraphically trapped hydrocarbons in the Cambrian sandstones. "The numerous shows indicate an active petroleum system with both conventional and unconventional trapping mechanisms."

Moreover, some of the most promising European shale's are offshore in the North Sea, and offshore production of shale gas has not been tried yet, which is more likely an issue of economics than of technology, according to the EUCERS report.

Shale Gas Exploration Sparks Controversy in Germany, Switzerland

However, controversy over hydraulic fracturing has sparked environmental and safety concerns in Germany and Switzerland, according to media reports.

View Europe's Shale Gas Potential in a larger map

ExxonMobil, which has licenses covering several million acres on which the company has been drilling and evaluating coal bed methane and shale gas resources, and other producers exploring for shale gas have faced opposition from local residents concerned about the impact of hydraulic fracturing activity on local water supplies or potential for earthquakes. According to media reports, Germany's Environment Minister Norbert Rottgen ordered a review of shale production's environmental impact in Germany following protests.

The state government of North Rhine-Westphalia also issued a moratorium in March on shale gas drilling due to pressure from environmental activists. Germany's Federal Environment Agency also has proposed issuing new mining laws that would ensure producers assess the environmental impact that each shale gas exploration well would have and ban fracking in areas where potable water is collected.

German oil and gas producer association WEG said in August that the existing mining laws already allowed enough protection for groundwater. WEG noted that approximately 300 deep wells have been drilled in Germany since June 1961, and that the fracturing process had not had any known adverse impacts on groundwater.

In April, the State Council of Switzerland's Fribourg Canton suspended all hydrocarbon exploration in the area for an indefinite period. A permit issued in 2008 to exploration company Schuepbach Energy, which was set to expire this year, was suspended, and no drilling permit was issued.

"The environmental consequences of extraction of hydrocarbons, including the extraction of shale gas, have not yet been clearly identified," according to a statement on the state's website.

Questions Need Answering to Realize European Shale Gas Potential

The groundwork for an expanded role of gas in the global economy has been established with the demand decline linked with the global recession, an increase in U.S. unconventional shale gas production, and the arrival of new liquefied natural gas (LNG) delivery capacity.

Theoretically, European recoverable shale gas reserves, which are estimated between 33 Tcm and 38 Tcm, could cover European gas demand for another 60 years. However, significant unconventional gas production in Europe is not expected to materialize before 2020.

A major obstacle to shale gas drilling in Europe is environmental concerns about hydraulic fracturing and its impact on the quality and quantity of local water supplies. Compared with the U.S., however, European unconventional gas resources are located more deeply and beneath groundwater, which raises exploration costs but lowers groundwater containment risk, the EUCERS report authors note.

They also pointed out that 70 percent of fracturing water used in most shale plays can be reused, and that technological improvements now make it possible to use water from brackish aquifers.

Still, a number of questions must be answered before shale gas potential can be fully realized, such as Europe's future energy market structure, the regulatory environment, political risk, investor confidence, public acceptance and competition with other fuels, especially renewables, according to the EUCERS report.

The density of Europe's population is a main factor, with environmental concerns needing to be addressed "as public acceptance will be the main issue for future unconventional gas development."

Unlike the U.S., where individual landowners control their mineral rights on their properties and receive revenues from development of their resources, the governments in European countries receive these royalties. This means landowners have less incentive to be inconvenienced by drilling if they cannot gain any profit from their subsoil's minerals.

While Europe's gas distribution infrastructure is well developed, the services sector that would support an unconventional gas industry is not, for which sub-contractors are already preparing for an anticipated increase in the level of activity.

"In addition, Europe also lacks suitable technical equipment, such as drilling rigs, and has extensive state control over local rig markets that reduces competition and leads to higher costs," the EUCERS report authors noted.

Additionally, unit supply costs, environmental regulation, pricing mechanisms, and market structures in Europe are different from those in North America, which will make the less- and knowledge-transfer between the continents difficult.

Good as Gould

Andrew Gould is the chairman and former chief executive officer of Schlumberger. He retired from his CEO post on Aug. 1, 2011, but will continue to serve as chairman until April 2012, when the shareholders will hold their next meeting.

According to Forbes, Gould stepped away from a lucrative annual salary of $2.5 million in 2010. Add to that additional compensations worth $214,375, option awards of $8.9 million, non-equity incentive plan compensation of $2.8 million and a change in pension value and nonqualified deferred compensation earning of $1.1 million, which equated to $15.5 million total compensation in 2010 alone.

After earning his degree in economic history from the University of Wales, Cardiff, Gould went to work for Ernst & Young. He started his career at Schlumberger in 1975 in the oil service company's Internal Audit Department based in Paris. Through the years, he was promoted to:

• treasurer of Schlumberger
• president of Sedco Forex, Wireline & Testing, and Oil-field Services Products
• executive vice president of Schlumberger Oilfield Services
• corporate president
• chief operating officer

From 1999 to 2002, Gould served as executive vice president of Schlumberger's Oilfield Services. He then served as the CEO of Schlumberger from February 2003 to August 2011, succeeding Euan Baird.

"A robust cash flow has allowed us to finance acquisitions, execute a large capex program and return considerable funds to shareholders.

In 2003, when Gould started his CEO role, he was tasked with reviving the company. Baird made Schlumberger a global company servicing many different industries. But when Gould took the helm, he thought it best to focus on its core business – energy. Thus, Gould sold off many of the non-core businesses such as Sema, Smart Cards and Electricity Metering, which brought in over $2 billion.

In the 2003 Annual Report, Gould wrote, "The year 2003 marked a watershed for Schlumberger as we took the decision to focus on our core businesses in oilfield services. Our reasoning was simple. World energy needs for much of the next half-century will be met mostly by carbon-based fuels produced from an aging reserves base."

Gould's plan to realign the strategic direction of Schlumberger was a success. According to the 2003 Annual Report, return on capital was 13 percent, compared to 7 percent in 2002. Net debt was $2 billion in 2004, compared to $4.1 billion in 2003. Oil field revenue increased by 9 percent in 2003 and EPS increased by 28 percent under Gould's leadership.

"Schlumberger revenue fell by 16 percent to $22.7 billion as world economic conditions worsened and customer spending dropped with lower commodity prices."

Growth peaked in 2006 with revenues of $29.23 billion, which was a 34 percent increase over 2005 and set a new record for Schlumberger. In the 2006 annual report, Gould said, "A robust cash flow has allowed us to finance acquisitions, execute a large capex program and return considerable funds to shareholders. These results, together with strong business fundamentals, have led us to extend our view and we now consider that high growth will be seen through the end of this decade and well into the next."

However, Gould would not see the breakneck pace of early 2006 again. Though growth continued through 2008, in 2009, Gould reported that "Schlumberger revenue fell by 16 percent to $22.7 billion as world economic conditions worsened and customer spending dropped with lower commodity prices."

Prior to Gould's retirement, the company released earnings for 2Q 2011. Now the world's largest oil services company, Schlumberger posted revenue of $9.62 billion versus $8.72 billion in 1Q 2011 and $5.94 billion in 2Q 2010. Net profits for 2Q 2011 was $1.34 billion, compared to $816 million 2Q 2010.

In the release, Schlumberger attributed the 2Q 2011 growth to strong deepwater and unconventional drilling in North America as well as the Libyan crisis. There was a surge in development and workover activity as producers moved to compensate for reduced Libya barrels and profit from higher prices.

Gould said in the earnings release, "Internationally, the trend toward higher deepwater rig count and higher exploration spending continued. As a result, all groups had standout product lines in the quarter and technology sales showed good progress."

Gould will remain as chairman until April 2012.He has been replaced by Paal Kibsgaard, the former chief operating officer who reported the company's 3Q earinings on October 21.

According to a release, 3Q 2011 earnings hit $10.23 billion versus $9.62 billion in 2Q 2011 and $6.85 billion in 3Q 2010.

Kibsgaard commented in the release, "Schlumberger third-quarter results continued to show solid progress with revenue increasing sequentially across all Schlumberger Product Groups."

Musings: How to Question Reserve Reports Without Any Knowledge

In what now seems like the distant past, The New York Times wrote a series of articles suggesting that industry practitioners were raising questions about the economic performance of the gas shale wells and thus whether the extent of the resource was over stated.  Those articles were written in late June and generated a firestorm of reaction within the natural gas industry, but also among Washington politicians. What followed was disclosure that a handful of E&P companies, active in the gas shale business, had received subpoenas from the Securities and Exchange Commission (SEC) for their records of well performance and the economics of behind their reserve calculations. The data was sought to compare with the companies' disclosure regulatory filings and investor presentations of the operational risks, production performance and economics of these gas shale wells. At the time the subpoenas were disclosed, we wrote about it in the Musings (last July), fully anticipating that there would be further disclosures. Since mid-summer, there has been no activity arising from the subpoenas. 

What followed was disclosure that a handful of E&P companies, active in the gas shale business, had received subpoenas from the SEC for their records of well performance and the economics of behind their reserve calculations

Our interest was piqued recently when we received a newsletter from an energy investment group we belong to that contained an employment ad for a petroleum engineer position with the SEC in Washington. We sent an email to the SEC requesting additional information about the opportunity, not that we were going to apply. Rather, we were intrigued by the idea that the SEC has launched an investigation into gas shale reserves, well productivity and well economics and then is seeking to hire a petroleum engineer. We wondered whether this position was to bolster a staff of petroleum engineers or was it a new position.

We received the usual email response – We have received your email request and someone from the SEC will respond in the next 24-48 hours. It wasn't until about four days later that we received a phone call from someone with the SEC. Unfortunately, we were unable to answer the phone so the caller left a voice message. The caller suggested that he had no idea whether the SEC employed any petroleum engineers and had no way of finding out. He suggested that we should contact the Fort Worth SEC office as that would seem to be the most likely office to employ such an individual. We did speak with the SEC official and ascertained that he had no idea what a petroleum engineer was, let alone whether the SEC employed any, and again received the suggestion to call the Fort Worth office.

She told us that the Fort Worth office employed one petroleum engineer who had been hired earlier this year

We called the Fort Worth office and spoke with a lady there and asked whether the SEC had any petroleum engineers on its staff.  She told us that the Fort Worth office employed one petroleum engineer who had been hired earlier this year. The SEC has 4,000 employees. That means if they hire another one in response to the Washington, D. C. office advertisement, the SEC will have a 100% increase in its technical talent for dealing with petroleum industry issues. Whether the new petroleum engineer position is a result of the proposed SEC study of gas shale disclosures we don't know, but we find it strange that they would inquire about technical information without having someone on the staff that could help frame the questions and review and interpret the data provided in response. 

What we haven't done is check on whether New York State, which issued subpoenas to three E&P companies and a data request to a fourth, as reported by the law firm of Andrews Kurth in an early September alert to clients, has any petroleum engineers on its staff.  The alert stated, "According to the published reports, the subpoenas seek information as to whether the companies have accurately disclosed the estimated commercial life of shale gas wells, the prospects for their natural gas wells and reserve estimates. The companies that received the subpoenas were reportedly selected because New York State pensions have more than $45 million invested in those companies and if the energy company disclosures are inaccurate New York State could lose some of its investment; they were not selected solely based on their operations in New York." If we had to guess, we believe New York doesn't employ petroleum engineers. They may hire some as consultants. Of course, the SEC can hire petroleum engineering consultants, also, but most likely not the prominent industry firms who would have conflicts of interest because they help E&P companies with their public documents filed with the SEC and state regulators.

Mr. Markopolos wrote a book in which he documented his investigation and dealings with the SEC that failed to understand the scheme despite the documentation or lacked the interest in pursuing an investigation

All of this brings us back to Harry Markopolos. For those who don't know of Mr. Markopolos, he was the financial fraud investigator who uncovered the Ponzi Scheme operated by Bernie Madoff. Mr. Markopolos began his investigation of the Madoff fund in 1999 and made multiple submissions of complaints to the SEC in Boston and New York providing documentation and information pointing to red flags demonstrating the existence of the scheme. Mr. Markopolos wrote a book, No One Would Listen: A True Financial Thriller, in which he documented his investigation and dealings with the SEC that failed to understand the scheme despite the documentation or lacked the interest in pursuing an investigation. Increasingly, the SEC has demonstrated that its staff is behind the financial industry in understanding new, sophisticated investment schemes and derivative securities. Lacking petroleum specialists, the SEC is probably behind on the disclosure of gas shales, too. We can only hope that their move to hire one or more petroleum engineers will enable the agency to better understand the technical aspects of E&P reserve calculations and well economics contained in the regulatory filings required of public companies and in their investor presentations. With a petroleum engineer or two, possibly the SEC will avoid another Bernie Madoff embarrassment.

G. Allen Brooks works as the Managing Director at Parks Paton Hoepfl & Brown. Reprinted with permission of PPH & B.

North Sea Rig Utilization Soars Above Global Average

North Sea offshore drilling activities are faring much better than worldwide operations. Total average utilization for region's mobile offshore drilling fleet is 92 percent, which compares quite favorably to the global average of 83 percent. The harsh environment along with a higher degree of regulatory oversight (especially in Norwegian waters) relative to the rest of the globe contributes to a limited participation by offshore drillers.

Dividing the region up into two parts (Norway in the North and the United Kingdom/Netherlands in the South) provides a clearer picture on average dayrates. In the southern section the going rate for a jackup is in the low-$120 k/day range. Conversely, jackup rigs to the north are averaging in the low-$310s. Both locales compare favorably to the worldwide jackup average, which is in the low-$100s.

A similar disparity due to capabilities and harsh environment demands exists for floaters as well. A floater operating in the southern waters of the North Sea commands an average dayrate in the low-$300s, while floaters to the north average in the high-$430s. We would note that the majority of the rigs servicing operators in the North Sea are suited for mid-water duties (i.e. less than 4000'). The global mid-water floater average is in the mid-$290s.

RECENT NEWS FROM THE REGION

Lotos Taps Maersk Guardian for One Well – Lotos has hired the Maersk Guardian (350' ILC) for a one-well contract offshore Norway. The rig will be used to drill Lotos' Skagen exploration well in PL 498 during 3Q12. The contract has an expected duration of 55 days at a rate in the low-$310s.

Ithaca Energy Hires WilHunter for Hurricane Appraisal – Ithaca Energy has contracted the WilHunter (mid-water semisub) to drill and test an appraisal well on its Hurricane discovery in Block 29/10b in the UK North Sea. The contract, which is valued at US $15.7 million, will start upon completion of the rig's current contract with MPX Ltd.

Noble Adds North Sea Backlog – Noble has added additional backlog to several North Sea rigs. The Noble Lynda Bossler, Noble Ronald Hoope and the Noble Piet van Ede have each received contracts from GDF Suez at rates in the mid-$110s. The Noble Ton van Langeveld has received a 5-month extension form Maersk Oil at the same rate (mid-$240s).

Centrica to Sidetrack Butch Discovery – Centrica Norge has made an oil discovery on its Butch prospect in PL 405 offshore Norway, encountering approximately 50 meters of net oil pay in the Upper Jurassic reservoir. The Maersk Guardian (350' ILC) will now drill a down-dip sidetrack to appraise further down on the large salt induced structure.

GDF Suez Exercises Option for GSF Galaxy – GDF Suez has exercised its option for the GSF Galaxy II (400' ILC). The dayrate for the three-well option is in the low-$190s, which is up from the rig's current dayrate in the high-$160s. The rig is still on the first well of the original firm contract. The prospect, Faraday, is an HPHT well targeting approximately 750 billion cubic feet of natural gas.

Mistakes to Avoid in RO Treatment Systems

By Wes Byrne

The requirements for a working reverse osmosis (RO) system are few; it needs a pump, some membranes, vessels, and plumbing. But operating the system in a way that minimizes membrane fouling, maximizes membrane life, and does not suffer from hydraulic catastrophes can be challenging. This paper discusses an assortment of issues that have led to RO performance problems and the way those issues were resolved.

Pretreatment Issues

The most common cause of a complete failure of an RO application is inadequate pretreatment of the RO feed water. RO systems must be protected from incompatible contaminants, from the potential for scale formation, and from excessive fouling. Compromises made in the pretreatment methods, monitoring instrumentation, or quality of the equipment will usually result in operational problems in the downstream RO unit.

For example, a common compromise is to use the same flow control orifice on a multimedia filter discharge line to control both the filter backwash flow rate and the rinse flow rate performed after a backwashing. This method results in roughly the same flow rate being used for both steps. But where a backwash flow rate based on 12 gpm/ft2 of cross-sectional area is appropriate for obtaining 40% expansion of the media granules (@54oF), this same rinse flow rate will compact the media granules under a pressure drop exceeding 10 psid. This will tend to push any suspended particles still in the upper section of the media filters deeply into the media bed. Acceptable performance will only begin to be achieved until after the flow rate has been reduced to the normal service flow rate. If this only occurs while the filter is in service, much of the solids shed by the filters will end up in the RO cartridge prefilters and in the RO membrane elements.

ORP should not be used to control sodium bisulfite injection when purified water is returned upstream.

Another common mistake with media filters is not installing individual flow meters on each of multiple filters in parallel. Without these flow readings, there is no way to know if flow rates are balanced between the filters. If any particular filter starts to plug up with solids, more flow will divert to the other filters. Keep in mind that pressure gauges on each side of the filters will not indicate if one filter is plugging more than another if they are on common inlet and outlet lines, in spite of whether they read differently because of their inaccuracies.

Poor location of transducers/gauges may impact performance.

If the media filter is not capable of providing water with a maximum silt density index (SDI) of 5, as noted as a requirement on some membrane manufacturers' element specification sheet, a fatal mistake is to inject a polymeric filtration aid directly prior to the media filters. This mistake is particularly devious in how it appears to dramatically improve the effluent quality of the filters. What does not show up in the effluent turbidity or silt density index analysis is the residual polymer breaking through the filter.

Because of the polymer's charge characteristics, it will permanently bond with the RO membrane. Any suspended solids will now attach to the polymer rather than migrating along the membrane surface. The rate of RO fouling will increase and cleanings will no longer restore original performance because it will not be possible to get the polymer off the membrane. The membrane elements will need to be replaced.

If media filters are not providing water of a sufficient quality, there are ways to improve their performance. A common misconception of pressurized filters is that they provide the best filtration at a flow rate of 5 gpm/ft2. Actually, filter performance will keep improving as the flow velocity is reduced until reaching the limits of the ability of the distribution laterals to prevent channeling.

It may be necessary to coagulate fine colloids upstream using a coagulant. If so, an inorganic coagulant should be employed, such as an aluminum product or ferric chloride. If these materials break through the media filter, they will also foul the downstream RO, but they can be cleaned. They should be used in a reaction tank of sufficient size to allow the reaction time necessary for the suspended solids to bind with the coagulant before getting to the media filters.

Chlorine Elimination

The polyamide thin-film membrane commonly used in most RO systems cannot handle chlorine. Some membrane manufacturers have promoted that their membrane could tolerate free chlorine equivalent to the exposure of 1 ppm over a period of 1000 hours before a doubling of salt passage would occur. This guideline has often been misinterpreted as meaning that it is acceptable to allow chlorine to occasionally contact the RO membrane as a means of reducing biological fouling. But membrane damage will soon occur if it is exposed to any amount of chlorine and will be cumulative. The damage will be worse if iron or other transition metals have fouled out on the membrane.

Sodium bisulfite is often used to reduce the chlorine concentration going into the RO. But sodium bisulfite will also react with dissolved oxygen in the water. Any excess bisulfite will tend to reduce the oxygen concentration, which increases the potential for increased anaerobic biological growth. These are the species responsible for heavy slime formations that can rapidly foul the systems. A definitive symptom of this is the sulfur dioxide, rotten-egg smell noted when membrane vessels are opened.

The optimum concentration of sodium bisulfite may be difficult to maintain. Sodium bisulfite present in the injection day tank or in chemical totes will degrade over time as it reacts with oxygen from the atmosphere. If sodium hypochlorite (bleach) is injected upstream, its concentration will also change depending on its age. Thus getting the correct bisulfite concentration injected relative to the chlorine concentration can be challenging.

ORP is a relatively inexpensive method of monitoring bisulfite dosage but its method may not directly reflect the residual chlorine concentration. Other variables can also impact its reading, especially pH.

When ORP is used to control bisulfite dosage on a continuously operating system, the results may be disastrous if the RO permeate returns back to an upstream feed tank when process water is not being demanded. During times of minimal usage, the increased concentration of RO permeate in the blended feed means that little alkalinity will be present. Added bisulfite will have an increased impact on the water pH and cause it to drop. The declining pH will cause the ORP reading to increase even if no chlorine is present. The control system will respond by adding even more bisulfite. The bisulfite injection pump will eventually max out on its dosage. All the excess bisulfite will deplete the oxygen in the water and a severe anaerobic bacterial outbreak will eventually result.

Scale Inhibition

The injection of a chemical scale inhibitor is typically the least expensive way to prevent scale formation in an RO system. These chemicals work by binding with the growing scale crystals, which reduces their particle growth rate. The smaller scale particles are more likely to remain suspended and exit the RO system in the concentrate stream.

A means of rinsing super-saturated salts from the RO prior to shutdown is essential to the success of this mechanism. The best method is to tee in pressurized permeate water with an automatic valve downstream of the inlet isolation valve to displace the water in the RO at shutdown. This has the added advantage of reducing the potential for anaerobic bacterial growth during shutdowns by reducing the concentration of anions in the RO, which are required for the anaerobic bacteria to proliferate. It also improves the quality of permeate during startup, which may mean that a permeate diversion system may not be needed at startups.

Homogeneous polyacrylic acid polymers are notorious for coming out of solution either due to over-injection, or due to a reaction with iron or aluminum. Sometimes they will even come out of solution with hardness if the injected chemical does not mix quickly at the point of injection. Blended inhibitors of two or more chemical components tend to perform better and are less likely to cause these problems.

Controls and Instrumentation

RO systems that will not be well attended by trained operators should have sufficient alarms and controls as to prevent catastrophic failures. The coordination of alarm conditions with system shutdowns is often performed with a human-machine interface (HMI). But if an HMI is employed, it is critical that either it is possible to make program modifications on-site, or that the HMI can be bypassed in case something goes wrong. An unforeseen problem in the program or a bad transducer should not prevent an RO system from being operated.

Accurate flow rate and pressure readings are critical to monitoring the performance of RO membrane elements. Flow transducers must be installed with a sufficient length of straight pipe upstream and downstream of the transducer as to meet the manufacturer's recommendations. Otherwise, the meter may not perform under reduced flow conditions.

Flow meters should be calibrated based on an accurate measurement of the flow rate. This may be as simple as timing the rate at which a downstream storage tank fills. The incorporation of redundant flow meters will assist in noting when a transducer is not reading accurately.

Pressure transducers should not be located directly downstream of throttled valves. The high localized water velocity created by the valve will cause an aspiration effect that will result in the transducer reading less than the downstream pressure. Incorporation of valved tees at the transducer location will make it possible to check all readings using the same calibrated gauge.

Installation

It is common for the RO concentrate stream to be plumbed to a discharge drain located beneath the highest point of the membrane pressure vessels. Unless an automatic isolation valve or a vacuum breaking valve is installed on the concentrate line, a siphon will be pulled on the RO while it is shut down. Water will continue to flow through the line after shutdown and will pull a vacuum on the RO system.

This vacuum will cause water to partially drain from the RO pressure vessels. Victaulic-style couplings enable this draining because their standard gaskets allow air to be pulled into the system to displace the vacating water. Specialty gaskets can be purchased that maintain a better seal under vacuum conditions.

When an RO drains, the incoming air will carry bacteria and fungi spores into the membrane elements. This may contribute to fouling of the membrane elements. When the RO re-starts, water hammer may occur, which can break the fiberglass wrap and plastic anti-telescoping devices (ATDs) on the end of the elements.

A check valve that uses a lightly weighted spring (1-2 psi) may be teed in the top of the concentrate discharge line to allow air to be sucked into the line under vacuum conditions. It should be directed or plumbed in a way that does not spit water at personnel whenever the RO starts up.

About the Author: Wes Byrne has 30 years of experience in the design, engineering and maintenance of membrane based water treatment systems and is a trained educator. He has been instrumental in troubleshooting hundreds of membrane treatment problems and has developed several new applications for membrane systems.

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Industry Questions Need for National Wastewater Standards

Last Thursday, the U.S. Environmental Protection Agency (EPA) announced that it will soon begin the process of developing "comprehensive" national standards for wastewater discharges produced by extracting natural gas from underground coalbed and shale formations.

In a written statement released by the agency, the EPA noted that proposed standard will include input from federal and state governments, industry and public health groups. EPA Administrator Lisa P. Jackson contends this latest action is necessary "to make sure the needs of our energy future are met safely and responsibly."

Federal laws prohibit the direct discharge of wastewater from hydraulic fracturing into waterways and other waters of the U.S. "Fracking" is key to the economic recovery of shale gas. Although companies do reuse or re-inject some wastewater into subsequent shale gas wells, there are cases where the wastewater must be transported to treatment facilities.

EPA contends that many of these treatment plants are ill-equipped to handle this type of wastewater. As a result, the agency will consider enacting standards that shale gas wastewater must meet before delivery to a treatment plant. EPA expects to unveil a proposed rule for shale gas wastewater in 2014. In the interim, it will continue to gather data, consult with industry representatives and other stakeholders and solicit comments from the public about the matter.

In regard to wastewater from coalbed methane (CBM) extraction operations, individual states—not the federal government—set regulations applying to its direct discharge into waterways and pre-treatment. EPA plans assert federal authority over this aspect of CBM production by proposing uniform national standards, which the agency anticipates proposing in 2013.

Industry's Response

The Pittsburgh-based Marcellus Shale Coaltion, which in its three-year history has established itself as a key voice for developing the Marcellus Shale play in an environmentally responsible manner, expressed bewilderment at the EPA's regulatory plans.

"While we certainly appreciate that the EPA shares our concern in protecting the environment, especially water, it is baffling that the agency would move forward with such measures that completely disregard the facts on the ground," said Kathryn Klaber, the coalition's president. "This is yet another Washington solution in search of a problem, as treated Marcellus water in Pennsylvania is no longer discharged into surface waters."

Another prominent industry voice, the American Petroleum Institute (API), maintains that operators' existing ties with state regulators have allowed them to tailor localized, effective approaches to managing produced water.

"As an industry, we work with state regulators directly to minimize environmental impact during the acquisition of water for drilling, water use during fracking operations and treatment and disposal of water and other fluids recovered after the well is completed," said Reid Porter, API spokesman. Porter added that industry has also increasingly integrated another environmentally friendly process into its operations: recycling produced water.

"API has developed guidelines for water management as one of a number of industry-developed standards designed to make hydraulic fracturing as safe and efficient as possible," noted Porter. "This current system of regulation already accounts for the fact that there is wide variability in the volume, regional environmental conditions and available management methods for produced water and the state regulators — who are in the best position to craft guidelines for their geography — are highly involved."

Back to the Blueprint

A driving force behind EPA's pending proposed standards is President Obama's Blueprint for a Secure Energy Future released earlier this year. It called on the Secretary of Energy Advisory Boar (SEAB) to form a Natural Gas Subcommittee that would recommend practices to improve the safety and environmental performance of hydraulic fracturing, or "fracking." The subcommittee released a preliminary report in August that presented the following findings and recommendations:

• Create a publicly accessible portal containing current data from state and federal regulators to disseminate information about shale gas operations and results.
• Improving communication among state and federal regulators by continuing to support both the State Review of Oil and Natural Gas Environmental Regulation (STRONGER) and to the nonprofit Groundwater Protection Council to expand the Risk Based Data Management System.
• Improve air quality by adopting "rigorous standards" for new and existing sources of methane, air toxics, ozone precursors and other emissions from shale gas operations.
• Protect water quality by adopting a water management approach based on consistent measurement and public disclosure of the flow and composition of water at every stage of the shale gas production process.
• Acknowledging the "remote" likelihood that fracturing fluid would leak into drinking water sources via fractures made in deep shale reservoirs, the subcommittee endorses disclosing the composition of fracturing fluid save for information that is "genuinely" proprietary.
• Using natural gas engines or electricity instead of diesel engines for surface power in shale gas production.
• Plan for shale development impacts on communities, land use, wildlife and ecologies on a regional scale. Possible ways to do this include using multi-well drilling pads to reduce transport traffic and new road construction, evaluating water use at the scale of affected watersheds and having regulated entities provide formal notification of anticipated environmental and community impacts.
• Creating a "shale gas industry production organization" to continuously improve best practices in order to improve operational and environmental results, particularly in regard to air and water.
• Setting a mission for federally funded unconventional gas research and development, particularly in regard to basic R&D, environmental protection and safety. The subcommittee also urges the Executive and Legislative branches of the federal government to provide "level funding" for such federal involvement.

The subcommittee plans to release its final report on November 18, 2011.

The EPA's pending regulatory action corresponds to the agency's effluent guidelines program, which sets national standards for industrial wastewater discharges. For background information on the program, see here.

Shale Gas a Major Contributor in Reducing Greenhouse Gas Emissions -API

Natural gas from shale formations represented a walloping $37 billion of the overall $108 billion that the petroleum industry invested in technologies to reduce greenhouse gas (GHG) emissions between 2000 and 2010, according to a new report released by the American Petroleum Institute (API) on October 20.

This $108 billion also comprised nearly half of the total estimated $225 invested by all private industry combined and the federal government in GHG-reducing technologies, noted Kyle Isakower, VP of Regulatory and Economic Policy for API. The new report showed a major uptick in such investments from the 2008 study due to the inclusion of shale gas and an increase in federal government spending on GHG emission reduction, Isakower added.

"Major investments by the oil and natural gas industry included shale gas (especially over the 2009-2010 period), efficiency improvements including combined heat and power, and advanced technology for vehicles. Investments in wind, biofuels and solar were also made," said the study, which was conducted for API by T2 Associates.

"Other private industries' major investments included advanced technology vehicles, efficiency improvements in electricity generation, biofuels, wind and solar," the report continued. "The federal government has spread investment across all technology categories with major investments in energy efficient lighting, wind, solar, biofuels and basic research. It also made significant investments in renewables and efficiency during 2009 and 2010 as part of the American Recovery and Reinvestment Act of 2009 (ARRA)."

Technologies' Shares of Investment

Six emission reduction technologies led the way in public and private investment. As measured by expenditure share, these were:

• Advanced technology vehicles (ATV), 22 percent of total investment or $49.5 billion;
• Shale gas, 17 percent or $37.7 billion;
• Energy efficiency, 14 percent or $30.7 billion;
• Ethanol, 8 percent or $18.4 billion;
• Wind, 8 percent or $17.4 billion; and,
• Combined heat and power CHP), 7 percent or $16.3 billion.

These six technologies comprised 76 percent of the estimated total investments, or $170 billion, between 2000 and 2010 period in North America, the report said. Meanwhile, all other technologies (including LNG, fugitive gas reduction and nuclear energy) combined were 24 percent of the estimated total investments.

Emissions-Reducing Impact

Picture 11 million cars off the roads. That's the impact that the above efforts represented just last year, in reducing some 56 million metric tons of greenhouse gas emissions, said API's Isakower.

Specifically, the report noted that fuel substitution accounted for 38 to 46 percent of the emissions reductions between 2008 and 2010. This included projects such as installing better plunger lift seals and improved well completion technology. Another 35 to 45 percent of the reductions came from combined heat and power, also known as cogeneration, projects over the same period. Remaining reductions occurred in the non-hydrocarbon areas, including solar and wind energy for electricity generation, as well as biofuels production.

UK O&G Workers Getting Younger

The number of workers younger than age 30 that are working in the offshore UK oil and gas industry has increased over the past five years, according to industry trade association Oil & Gas UK's 2011 Workforce Demographics Report.

The presence of younger workers is helping rejuvenate the offshore population, "which many still wrongly believe is aging," Oil & Gas UK reported earlier this month.

The average offshore worker's age is 41, which is normal for a workforce whose ages range from 20 to 60, and is consistent with Oil & Gas UK's findings in previous years.

The report noted a net loss of people within the 30-60 year age range. "Workers in this age range tend to relocate to other oil and gas regions around the world or return to onshore roles," Oil & Gas UK said.

"Their departure leaves vacancies which must be filled by suitably skilled and experienced candidates, with demand often outstripping supply and raising concerns about a possible future shortage of supervisors."

While Oil & Gas UK Chief Executive Malcolm Webb was pleased to see more young people working offshore, the loss of experienced workers is a concern. Webb noted that "fast-track development programs are now in place to address ongoing skills shortages in certain occupations."

North Sea Offshore Drilling Rises in 3Q, but Overall Decline Continues

North Sea offshore drilling activity rose 45 percent from the second to third quarter of this year, according to Deloitte's North West Europe Review, a quarterly report of drilling and licensing on the UK Continental Shelf.

However, the overall trend for UK Continental Shelf drilling activity continues to decline. Sixteen exploration and appraisal wells were spud between July 1 and Sept. 30, up from 11 in the second quarter but still 36 percent fewer than the same period in 2010.

So far this year, 37 wells have been drilled, a 41 percent decrease from the same period last year and the lowest number drilled in this period since 2003, Deloitte noted, an unexpected trend given that the average oil price is over US $100/bbl.

Outside the UK, buoyant oil prices have driven high levels of drilling activity in North West Europe. The Norwegian sector recorded 16 wells spud in third quarter 2011, double the number compared to the same period as last year and the same level seen in 2009, which saw the highest levels of drilling activity on the Norwegian Continental Shelf to date.

"It could be that factors including the relative geological maturity of the UK sector, compared to some adjacent regions, and the alterations made to the UK fiscal regime earlier this year have impacted business confidence," said Graham Sadler, managing director of Deloitte's petroleum services group.

Graham noted that some smaller, UK-focused companies may also have experienced difficulties securing finance to fund exploration and appraisal drilling in recent months.

"A combination of the tax increases announced in the 2011 Budget and general market instability around the Eurozone crisis, has led to some of these companies losing significant corporate value," Graham said.

Corporate dealmaking also rose during the quarter, with four acquisitions announced, while the level of farm-in activity declined from the second quarter.

Despite Production Decline, Optimism Grows Over Offshore UK Investment

The Department of Energy and Climate Change (DECC) estimates UK Continental Shelf oil and gas production to continue to decline through 2016. DECC reported in late September that aggregate UK oil production for second quarter 2011 experienced the largest quarterly decrease seen since quarterly reporting began in 1995. UK natural gas production was a record 24.8 percent in the same quarter versus second quarter 2010.

However, UK Energy Minister Charles Hendry told attendees at the Offshore Europe Conference in Aberdeen in September that 2011 appeared to be shaping up to be the UK's best year for new development in at least a decade, "on par with some of the very early years of the industry."

The UK North Sea will get a significant dose of new investment with the UK government's approval of the $7.1 billion development project for the Clair Ridge project by BP, Shell, ConocoPhillips and Chevron. Clair Ridge is the second phase of development of the Clair field west of the Shetland Islands. The investment represents the highest level of annual investment the company has ever made in the UK North Sea.

Industry association Oil & Gas UK praised the Clair Ridge announcement, saying the investment was a boon for the UK's economy and its energy security. However, smaller projects with more marginal economics are struggling.

"While we believe that up to 24 billion barrels of oil and gas are still to be extracted, there is evidence that, following the tax increase announced earlier this year, well in excess of one billion barrels of the UK's oil and gas resource are 'fiscally stranded' which is to say that the current tax system renders them uncommercial," said Malcolm Webb, chief executive of Oil & Gas UK.

Other significant UK North Sea investments include BP's plans to invest US $1.1 billion in the Kinnoull subsea development, the largest of three reservoirs being developed as part of the Andrew area development project in the central North Sea.

Wood Mackenzie estimates that total spending on UK oil and gas development projects will be US $38.2 billion in 2011 terms, higher than the development spending level seen in 2010. Significant progress is being made towards bringing 50 offshore UK fields containing more than 2 billion BOE towards development sanction.

However, Wood Mackenzie noted in a recent report that maintaining this pipeline of new projects and developments will require significant exploration success and continued investment in the UK offshore oil and gas sector.

NPD: Significant Oil Resources Remain on Norwegian Shelf

The Norwegian Petroleum Directorate (NPD) on Oct.12 said the number of major discoveries made in the Barents Sea and North Sea this year confirm its belief that significant undiscovered resources still remain on the Norwegian shelf.

"The remaining resources can form the basis for considerable production and value creation for many years to come," NPD said in conjunction with the publication of its report Petroleum Resources on the Norwegian Continental Shelf.

NPD estimates that future oil and gas production will remain at current levels for the next decade, in spite of a graduate decline in production from major fields. Measures to increase recovery and start production from discoveries will contribute to maintaining production.

"After 2020, production from undiscovered resources will account for an increasing share of the expected production," NPD said.

New production sources will come from discoveries such as Lundin's Avaldsnes and Statoil's Aldous Major South discoveries. Lundin President and CEO Ashley Heppenstall said Avaldsnes and Aldous Major South, which are connected with the same oil water contact, pressure regime, oil type and reservoir, could be among the largest five discoveries on the Norwegian Continental Shelf. The two discoveries will be jointly developed, Heppenstall said last month.

Lundin on Oct. 18 reported that appraisal drilling has confirmed the northern extension of the Aldous Major South discovery in PL265 in the Norwegian North Sea. Prior to appraisal drilling, Statoil had previously estimated Aldous Major South to hold between 400 million to 800 million barrels gross. Avaldsnes is estimated to contain gross Contingent Resources of between 800 million and 1.8 billion barrels of recoverable oil.

However, discoveries such as Avaldsnes and Aldous Major are exceptions to the trend seen of average discovery size on the Norwegian shelf as being much smaller than before, and exploration costs have increased, according to an NPD analysis of exploration profitability from 2000-2010.

More exploration drilling and injection of gas and water into wells will be critical towards recovering more oil from the Norwegian Continental Shelf. In addition to the injection and drilling of wells, "it is important that advanced injection methods and new technology are developed and qualified through field test. This can further improve recovery," NPD said.

Norway and Russia's ratification of maritime boundaries in the Barents and Arctic seas has opened up a new exploration frontier. NPD also reported earlier this month that the Norwegian government would fund seismic acquisition in 2012 for the southeastern Barents Sea and other frontier exploration areas offshore Norway.

NPD also is seeking to improve recovery from chalk fields on the Norwegian and Danish shelves. To achieve this goal, NPD, the Danish Energy Agency and 10 oil companies will cooperate on research and development and share experiences in this area. The companies involved with contribute funding for this effort starting in 2012 for a three-year period.

Only 6 days remain to regsiter for Drilling & Completing, Galveston Texas

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FUEL FOR THOUGHT - Energy News, Careers, Analysis & Technology - 24 / 7 / 365 October 25-27, 2011 Galveston Convention Center "Challenging Problems, Collaborative Solutions" The International Association of Drilling Contractors, along with Petrobras and NOV, invite you to attend the 6th annual DCTZ Forum. The keynote presentations, delivered by Bernard Duroc-Danner, CEO, Weatherford International and Jip van Eijden, Shell R&D, will kick off the conference. Throughout the next two days, sessions will be led by industry leaders from Shell, Devon, Chesapeake, Petrobras, and many more. Products on display on the exhibit floor include: contracting services, directional drilling and measurements, exploration and production, instruments and control, lubricants, pump and pressure equipment and services, safety equipment and systems, and well completion. CLICK HERE to view the Agenda and Show Program Forum Highlights: Tues, Oct 25th, Horizontal Drilling Workshop - The participants will come away with an understanding of the tools and methodologies applicable in their specific reservoirs. By sharing examples of successful and unsuccessful horizontal well applications and interpretations the development community can increase its production and reduce costs. Workshop leaders are from ExxonMobil, Shell, Forest Oil, MI Swaco, @Balance, Baker Hughes, and WWT Shell Research & Development, Jip van Eijden, Shell Global Solutions, Netherlands Case history presentations by Devon Energy, Taylor Energy, Chesapeake, Petrobras Electronic Audience System to keep the audience engaged throughout the two day event "Pad Drilling using Magnetic MWD," Devon "Shale Completion Challenges," by Weatherford "Relief Well Planning into Execution," Will Pecue, Taylor Energy "Drilling Rig Electrification," Chesapeake Compelling Operator Panel including Petrobras, Devon, Chesapeake, and Shell discussing Collaborative Solutions Looking ahead to 2012 business development: Excellent networking opportunities with cocktail receptions, lunches and continental breaks The conference board has once again solicited a number of timely and cutting-edge presentations by industry leaders. You must participate in this conference to receive its benefits, as proceedings will not be published and no press is ever allowed in the conference area. This is truly a closed forum with open discussion, where the information shared inside the conference room stays inside the conference room. We hope you will join us. For more information or to participate in this event, please contact Ray Vanegas, CMP at 713-874-2207 or rvanegas@oilonline.com . For sponsorship and exhibit information, please contact Lisa Zadok at 713-874-2215 or lisa@oilonline.com

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How to Trade Oil

Crude Analysis: How to Trade Oil

Source: Chris Vermeulen, TheGoldAndOilGuy  (10/20/11)

"In today's headline-driven market, it's important to be able to spot trends and understand price and volume in an intraday time frame."

Trading oil is not an easy thing to do in today's headline-driven market. Even the best oil analysis who may have been correct will still be wrong at times. This is due to the fact that oil has many factors which play into its price, things likes like extreme weather conditions, geopolitical events, currency fluctuations, economic conditions and supply and demand.

During any time of the day, oil traders and their oil analysis stand a good chance of having one of these factors directly affect the price of crude oil messing up their charts.

But I am a firm believer that these factors (news events) generally fall in line with the overall larger trend of oil. Understanding how to spot trends in oil is a vital part of the equation.

Another important aspect of trading crude oil along with stocks and commodities is for you to understanding how to trade price and volume at an intraday time frame. If you don't understand candle sticks, chart patterns and volume will get your head handed to you more times than not.

Let's take a look at some charts and my short video which cover everything you need to know in great detail. . .

How to Trade Oil Daily Chart Analysis:

Below you can see clearly how the overall trend is down for oil. You can also see the repeated bearish patterns and key resistance levels. In my oil analysis I focus on finding and trading the trend. You will not find me trying to pick a major top or bottom with my strategy; rather I focus on low risk high probability continuation patterns within a trend.

Once the trend stops and reverses there will likely be one or two losing trades as the investment shakes things up and sentiment slowly comes around and shifts to support the new trend in oil.

Intraday Crude Oil Analysis:

This is a chart of Oct 19th using a five-minute interval. The annotations on the chart explain clearly what I saw and was hoping to see for an oil ETF trade setup this week.

Watch My Eight-Minute Crash Course on The Gold ReportHow to Trade Oil

How to Trade Oil Conclusion:

In short, I have been waiting for this setup to unfold for a few days now. This report goes to show that if you have the patience to site back, watch and wait you will trade with much less risk. By doing this you reduce risk on your overall position because you can time your entry 1-3 days before oil moves in your favor getting you the best possible price. Also the less time you have to keep your money in a trade the better because of the factors (news events) I told you about earlier. Cash is king! Get my bi-weekly reports and videos by joining my free oil newsletter here: www.GoldAndOilGuy.com

Opportunities in Shale Drilling

Gary Bryant: Opportunities in Shale Drilling

Source: George Mack of The Energy Report  (10/20/11)

After nearly 30 years as an investment banker and another 20 years providing consulting to small companies, Newport Capital Consultants Founder and President Gary Bryant knows all the ins, outs, risks and rewards of small-cap investment. In this exclusive interview with The Energy Report, he shares his knowledge on what factors push small- and mid-cap growth, as well as some surprising new business models changing the dynamics of shale drilling.

Companies Mentioned: CAVU Resources Inc. - Continental Resources Inc. - Devon Energy Corp. - Eagleford Oil & Gas Corp. - GMX Resources Inc. - Lucas Energy Inc. - Magnum Hunter Resources Corp. - U.S. Energy Corp. - Williams Companies - Xtreme Oil & Gas Inc.

The Energy Report: Gary, can you tell us about your background in small- and micro-cap stocks? You have a special interest in these.

Gary Bryant: I do. The microcaps and smallcaps have been my expertise for a number of years. I got in the business in the '60s, and in December 1963 I got a securities license. In 1965 I was fortunate enough to start my own brokerage firm, Anderson, Bryant & Company with my partner Anderson, and we did a lot of small-cap deals through the years. I was lucky enough to be one of the founders of the Regional Investment Bankers Syndicate, which was the forerunner to the National Investment Bankers Association. That began in response to deregulation in securities markets in '78, which made it difficult for small-cap brokers to operate because the large-cap brokers could no longer do business with them on those syndications. It worked really well, and we were able to syndicate a lot of offerings that way.

TER: You have said that the small- and micro-caps are key to a vital economy. Can you elaborate on that?

GB: In the United States of America, it's the real way to employ people in the absence of large-scale manufacturing. But small companies need funding, and it's been a lot harder since September 11 to get anything done. Some of the small-cap companies that I have helped fund went from zero employees to 1,200 in a matter of three years.

TER: Aside from obvious liquidity issues, what are some dangers of investing in small- and micro-cap stocks?

GB: Let's say you buy an SEC Rule 506 private placement, and you put $25,000 into it. These have to be accredited investors, meaning sophisticated, high net worth corporate or institutional investors. Thus, most of the time companies do get pretty good amounts of money. But what happens if they sell to only five or 10 investors and raise a quarter of a million dollars when the business plan calls for $1 million (M) or $2M? If you're stuck in a company that didn't get enough funding, you stand a good chance of losing your money.

Another problem is that even after they've raised capital, a lot of small companies don't have sales to justify being public. It happens all the time. However, there are many counter-examples that do get enough funding to successfully go public.

TER: Gary, what do you do for companies today?

GB: I consult for these companies and introduce them to investment bankers and capital markets. I was an investment banker all my life, and I know that business very well. I have strong relationships with broker dealers around the country.

TER: When you take a micro-cap deal to an investment bank, what's the first question they want to ask you?

GB: The first question is always, "What are their sales?" Most investment bankers qualify companies based on their sales. If your company has $1M or less in sales, then it's definitely a startup. If you're anywhere from $2M to $10M in sales, you're barely getting started. They can work with you a lot better at $50M or $75M in sales.

TER: Does the investment banker want to know how much of this stock you are going to buy, and how long you will hold it?

GB: Not really. I often put my own capital into companies. And if I do, I'm sure to tell them about it. But they would rather I own stock than not.

TER: Aside from lack of sales, what conditions would prompt you to advise a company to wait six months or a year to go public?

GB: Sometimes companies want to go public, but they frankly just don't need to be public. The management doesn't have the experience to be in a public arena. Sometimes companies go public too soon. For example, a fast-growing company may only have $2M or $3M in sales, but its product is good and it is likely to increase sales to $10M the next year or $20M the next. It would behoove the company to hold off until bigger brokerage firms are considering underwriting the company, and when it could get a bigger offering and a much higher market cap.

TER: Does the investment bank want to see that management has mortgaged their houses and gone to their family and friends first?

GB: Sure. That's usually the way it starts out. I'll just give you an example: The founders of the company sometimes put their money in before going to friends and family. The friends and family are usually accredited investors, and will invest half a million or $1M. That will be enough to push the company to the next stage, where they can do another larger private placement and later go public.

TER: What's the sweet spot in market cap size where a company is small enough to give investors huge gains but large enough so that mutual funds can own it?

GB: It's different with almost every company. Generally, companies under a $75M market cap sometimes have mutual funds and hedge funds investing, but not often.

TER: I think you were the lead consultant on Petro Resources, which was later taken out by Magnum Hunter Resources Corp. (MHR:NYSE.A).

GB: That's true. The other day I had the pleasure of talking with Brad Davis, senior vice president of capital markets at Magnum Hunter. The stock came down considerably from $8 to around $4. He said the company was three times better off than it was at $8, yet the general public is not paying the price for the stock. Sometimes stocks trade in a certain range.

Magnum Hunter bought three companies in the past two or three years that had sellers in them, and all of a sudden they get the benefits of a New York Stock Exchange company with a lot of liquidity. I think this is one factor that has caused the company to sell off. You never know.

TER: You're interested in shale-fracking technology. Will this become the new conventional technology as low-hanging fruit dries up?

GB: Absolutely. Hydraulic fracking on shale plays is a tremendous invention. Ten years ago this technology was not developed. As a young man going to high school, I worked on some drilling rigs just to make enough money to buy a car. But when we hit shale, it was a really bad situation. Today they've learned how to go down to depth and then go two miles horizontally. I saw them fracking one of the Barnett Shale wells the other day. It is definitely the new-and-improved process with horizontal drilling.

TER: Do you have any favorite shale-fracking companies?

GB: Certainly. I like the major players, such as Continental Resources Inc. (CLR:NYSE), Devon Energy Corp. (DVN:NYSE) and Williams Companies (WMB:NYSE). They have been doing a lot with these particular formations. Now Magnum Hunter has interesting plays in the three big shale formations: the Eagle Ford, the Marcellus and the Bakken. Of course, there are a lot of other shale players too, like GMX Resources Inc. (GMXR:NYSE) on the border of Texas and Louisiana. It's a gas play, and it's doing pretty well.

TER: Are there any small- or micro-caps you have good feelings about right now?

GB: There's one called Eagleford Oil & Gas Corp. (ECCE:OTCBB) and another called U.S. Energy Corp. (USEG:NYSE), which is run by the Larsen Family. U.S. Energy appears to be doing very well in the Bakken formation in addition to having success in its Wyoming production. I like Lucas Energy Inc. (LEI:NYSE.A). I like CAVU Resources Inc. (CAVR:OTCPK). Billy (William C.) Robinson is the CEO. He's kind of changing his tune on how he's doing business, as are others who are discovering opportunities in the sector beyond oil itself. For example, Xtreme Oil & Gas Inc. (XTOG:OTCBB) and CAVU are both drilling water disposal wells and making quite a bit of money by charging producers for water disposal services. Shale drilling involves getting rid of a tremendous amount of water, which has become a big problem over the last 10 years. For every barrel of oil recovered, some water is also extracted, and it's not like drinking or ocean water. It's more of a brine—twice as heavy and loaded with salt and chemicals.

TER: Do water disposal services de-risk these plays?

GB: They do, because the process alleviates an environmental problem by putting water back in the right sand. Companies build what are called saltwater disposal wells, and drill 4,000–5,000 feet, similar to an oil well. They reach a deeper, different type of sand in which they deposit the water, so it won't touch drinking water sources.

TER: Gary, Xtreme Oil & Gas has been hurt pretty badly over the past 12 months. It's down about 76% over that period, and it has a market cap of under $14M. Why have investors forgotten it?

GB: Knowing this company as well as I do, I know that it was a Gray Sheet company for years, and there was hardly any market in the stock. So when they registered on the Bulletin Board, it was trading around $1, but lightly. Market breaks have suddenly come in and driven the stock down. I've talked to CEO Will McAndrew about this, and the company has earned money two quarters in a row. Its disposal well business should help provide more sales and earnings. It's one of those situations where the company has been improving but the stock has been going the wrong way.

TER: What do you think would get investors' attention here?

GB: Making money three quarters in a row would probably do the trick. It needs to attract more institutional buyers and get the word out. I'm a believer in the value of attending conferences. The company has to do more PR and get some publicity from companies like The Energy Report.

TER: That micro-cap size is just a tough nut to overcome.

GB: It's a very tough nut to overcome. No one has the solution to that. But Will McAndrew can get them out of the ditch. I see it every day. Before the Magnum deal, Petro Resources was a Pink Sheet-type of company, but it went out and raised a lot of money, so it was able to go from Pink Sheets to the American Stock Exchange. A large brokerage firm jumped on them and loaned them $75M to acquire properties up in North Dakota in the Williston Basin. Once companies get the ball rolling, doors open, but that first push is tough sometimes.

TER: Gary, it's been a pleasure meeting you.

GB: My pleasure. Thank you.

Gary Bryant is the current president and founder of Newport Capital Consultants, Inc., an Orange County, California-based firm that has been providing consulting services to private and public companies since 1991. Since gaining his securities license in 1963, he has gained over 40 years of experience in the investment banking services industry, and was recently involved as a co-founder of the Southern California Investment Association (SCIA), which offers select small-cap companies a venue to present to investment professionals. In December of 2006, Gary received the prestigious "Founders Award" from the National Investment Banking Association, and in October of this year he was honored with a lifetime achievement award from the West Coast Wall Street Conference.

Want to read more exclusive Energy Report interviews like this? Sign up for our free e-newsletter, and you'll learn when new articles have been published. To see a list of recent interviews with industry analysts and commentators, visit our Exclusive Interviews page.

DISCLOSURE:
1) George Mack of The Energy Report conducted this interview. He personally and/or his family own shares of the following companies mentioned in this interview: None.
2) The following companies mentioned are sponsors of The Energy Report: U.S. Energy Corp.
3) Gary Bryant: I personally and/or my family own shares of the following companies mentioned in this interview: Magnum Hunter Resources Corp., Continental Resources Inc., Chesapeake Energy Corp., Devon Energy Corp., GMX Resources Inc ., Eagle Ford Oil & Gas Corp., Lucas Energy Inc., CAVU Resources Inc. and Xtreme Oil & Gas Inc. I personally and/or my family am paid by the following companies mentioned in this interview: None.

Massive Natural Gas Discoveries in Northern Spain

Massive natural gas discoveries in northern Spain are reportedly sufficient to supply the country's requirements for five years.

Spain's Basque regional premier Patxi Lopez says that surveys in Alava province have identified 13 unconventional gas holdings totaling 180 billion cubic meters in Gran Enara, which could supply the Basque region for six decades, or the entire nation for five years.

The natural gas deposits are located in shale rock deposits, which would require hydraulic fracturing to release them, a contentious technique which has encountered growing resistance in the United States, where the method was first utilized, as well as in other countries.

Despite such environmental concerns, Remier Lopez told the media that the Basque regional government will invest $55 million in the project while U.S. companies Heyco Energy and Cambria Europe will jointly invest $82.4 million, Madrid's El Pais newspaper reported. According to Lopez, Basque government studies have found a total of roughly 185 billion cubic meters of shale gas in 13 wells in the Gran Enara field in northern Spain's Basque Alava region.

According to preliminary reports, two wells are to be drilled initially in the Gran Enara field to see if natural gas extraction is technically feasible and economically viable.

(Charles Kennedy is Deputy Editor of OilPrice.com. The original article appears here.)

Reliance Industries Suspends Drilling at Blocks under BP Deal - Source

Reliance Industries has suspended drilling at all the 21 oil and gas exploration blocks covered under a deal with BP for two-three months starting early October, a person with direct knowledge of the matter said Monday.

The drilling suspension is part of plans by Reliance, India's largest company by market value, to revamp its exploration program with BP, the person, who didn't want to be identified, told Dow Jones Newswires.

"There is a team of six people, three each from BP and Reliance, that has been looking at the data," the person said, adding that "they will review the work that has been done at the blocks so far and suggest changes." More people will join the team over the next few months, the person said.

The person said Reliance wants to "see to it that it doesn't waste money on drilling dry wells" and "optimize the drilling costs."

BP India didn't immediately respond to a request seeking comments.

Reliance, controlled by billionaire Mukesh Ambani, has been struggling with declining gas output at the D6 block in the eastern offshore Krishna-Godavari basin. KG-D6 is India's richest gas find so far, with estimated reserves of 10 trillion cubic feet, and is likely to generate revenue of $38.3 billion, according to upstream regulator Directorate General of Hydrocarbons.

Reliance's share price has fallen 30% from a year high of INR1,187 in November 2010, to close at INR833.20 Monday on the Bombay Stock Exchange, largely due to worries over KG-D6 production.

Reliance on Aug. 30 closed a $7.2 billion deal with BP to sell a 30% stake in 21 exploration blocks in India, including in the D6, as part of its strategy to utilize the British energy giant's expertise in deepwater drilling to revive oil and production levels.

Experts from Reliance and BP will reconsider the initial drilling plan for both onshore and offshore exploration blocks, and evaluate new data on the highly complex reservoir at KG-D6, the person said.

"The integration process with BP is underway," analysts Anil Sharma and Ravi Adukia at Nomura Financial Advisory and Securities India Pvt. Ltd. said in a note. Joint teams are also reviewing the strategy for developing resources, including maximizing output from the D6 field and setting up an equally owned joint venture for gas sourcing and marketing, they said.

Copyright (c) 2011 Dow Jones & Company, Inc.

The Great Crew Change: 'Honey, How Are We Going to Train All These Kids?'

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The petroleum industry is amid a tremendous wave of hiring that's occurring in response to the gradual retirement of the so-called "baby boom" generation, which was spawned in the wake of World War II.

Much of the hiring focuses on the very young—both blue collar labor and newly minted petroleum geoscience and engineering grads. Another important trend is on the re-training of mid-career professionals into more labor-tight technical and management positions.

The American Petroleum Institute says that it has no statistics on how much hiring is directed toward the young and middle-aged, but other statistics are compelling on how badly replacements are needed for aging "baby boomers."

For instance, by 2012, the peak (mode) age of petroleum engineers and geoscientists will be 60, versus only 45 in 2000, according to Pete Stark, VP of Industry Relations at IHS, a company focusing on energy, economics and geopolitical risk.

In a survey of technical oil company professionals age 55 and over by the recruiting firm Working Smart, the average intended retirement age was found to be 65, with only 23 percent seeking to work beyond retirement age.

Meanwhile, within a few years, the majority of new technical professionals in the oil and gas industry will have less than five years of experience, increasing the chances of serious, costly mistakes and accidents, according to J. Ford Brett, managing director of PetroSkills, a petroleum training company.

Training Intensifies

Such alarming trends have the industry focused on training programs while skilled, experienced people are still available. One much-discussed resource is the mentoring of younger people by older ones, including already-retired workers who either come back to the industry voluntarily to train – or sometimes, are recruited back specifically as mentors.

One example of a formal mentoring program is ConocoPhillips' Legends effort.

"The program brings back senior project managers from retirement to train younger hires," explained Carsten Alsguth, a professional engineer with ConocoPhillips.

Mentoring also is available through professional organizations, such as the Society for Petroleum Engineers (SPE). For instance, SPE has an online mentoring program, www.spe.org/ementoring. In addition, the group's Gulf Coast Section is considering a new program to match up the Legion of Honor (SPE members for 50+ years) with young professionals in a mentoring program that would swap hard-earned field experience for help from younger members with high-tech products.

Such mentoring programs are no doubt on the rise, although measurement of how much they've increased is difficult. Still, a survey by SPE's Young Professional group, which appeared in a 2006 group magazine called The Way Ahead, found that mentoring was a "common practice" among only 37 percent of survey respondents at the largest companies profiled (more than 3,000 employees), and was not practiced at all by 46 percent of mid-sized companies and 44 percent of small companies in the survey. While the survey is indeed dated now, it shows how badly mentoring needed to grow just within the past five years.

A separate briefing paper on the great crew change by Rigzone, found (among other things) that in addition to mentoring, some companies are stepping up the intensity and duration of in-house training while experienced professionals are still available to train newcomers. One such program is Chevron's Horizons initiative, a formal five-year training program available to recent graduates that provides a curriculum of technical courses and practical experience opportunities led by skilled and experienced professionals as trainers.

Offsite training programs are also experiencing growth. For instance: Boston-based International Human Resources Development Corporation (IHRDC) added several new courses for 2011; PetroSkills' new training center in Katy, TX, is burgeoning with students and SPE has increased the number of short courses offered from roughly two dozen to more than 80.

Some companies, such as ExxonMobil, also are hiring people not for existing jobs, but to be trained for anticipated future openings. One example is Andrew Wolke, 23, a construction engineering technician hired and being trained as a rig supervisor.

When asked if he was concerned about becoming a victim of layoffs in a future downturn of the highly cyclical petroleum industry, Wolke replied confidently, "Absolutely not. I'm not worried at all."

When asked why, Wolke explained, "I'm not even sure they need me now – except to be trained while experienced trainers are still available. They need people my age so badly, it's not even funny." (click here for full story)

Yet indications are that actual on-rig experience of newer hires is limited.

"Something ironic that I see is a number of my students who are being trained as rig supervisors, but have never been on a rig yet," said Dr. Leon Robinson, 84, himself a retired ExxonMobil physicist and renowned drilling expert, now a trainer with Petroskills.

Indeed, adds Petroskills' managing director, Brett.

"The aptitude, you can hire. The knowledge and skills, you have to develop. Solving the problem will require deliberate programs to develop younger talent," Brett said.