New System Offers Holistic Approach to Frack Water Treatment

A wastewater treatment process long utilized in the food industry now is available to treat flowback and produced water from hydraulic fracturing.

Established in 2002, Alpharetta, Georgia-based Ecologix Environmental Systems has provided wastewater treatment services to companies such as Tyson, Kellogg's and Toyota as well as mining and metal plating industries.

The company has reached agreements to ship its wastewater treatment management system to oil and gas customers in Canada and Texas. These units are the third generation of systems geared towards the oil and gas industry – the company previously had sent protoypes into the field in Oklahoma and Texas' Permian basin to learn the lessons of what and what not to do. These lessons include everything from how to maximize unit performance, improve manufacturing and make the units more user-friendly in terms of maintenance and ground operations.

The company also sold a prototype unit to Halliburton Co. that reduced the turbidity level from 530 nephelometric turbidity unit (NTU) to just 3 NTU, a 176 fold improvement in water clarity.

When Ecologix CEO Eli Gruber looked at the oil and gas industry, he saw nothing had been done to address wastewater treatment in a way that made sense to him. Various companies had rushed in with black box ideas, but Gruber still saw a need for a water solution to correct the whole spectrum of contaminants.

"Other companies who rushed in do one thing well, but they ignore five other things," Gruber told Rigzone in a recent interview. "We attempt to take care of every step along the way to  both clean and disinfected the water."

Ecologix Environmental Systems' flagship ITS-900 units for frac water recycling. Each system can process up to 31,000 barrels per day of flowback or produced water.

Ecologix's Integrated Treatment System (ITS) for hydraulic fracturing water treatment allows water to be treated near the well pad, allowing the storage and transportation costs of produced and flowback water to be eliminated.  The ITS also eliminates the need for fresh water withdrawal, shortens hauling distances and reduces truck traffic and creates reusable water from waste, eliminating need for water disposal.

The platform uses a basic wastewater treatment process, Dissolved Air Floatation (DAF), which uses targeted chemicals to precipitate oils and solids out of suspension and a physical mechanism to remove these solids from the water.  In the DAF process, millions of tiny air bubbles force total dissolved solids and fats oil and grease to flow to the surface, where they can be skimmed away. Through this process, over 99 percent of the sludge can be removed.

The ITS-900 consists of three main units:

to control chemical dosingto mix the chemicals into the waterto perform the physical separation of solids

The ITS process is flexible, and can be adapted to meet the specific needs of the formation and driller preferences.

The ITS platform is available in two sizes: one that can process 900 gallons per minute, or 31,000 barrels per day, and a fourth generation ITS that can process 500 gallons per minute, or 17,000 barrels per day. The fourth generation ITS has a lower processing rate, but it has a smaller footprint that combines equipment from two trailers into one. The company will limit production of the units to the smaller unit, noting that customers can always choose to utilize two ITS-500 units, if the volume of water justifies it, Gruber noted.

"However, the 17,000 barrels per day unit seems to be within the industry's sweet spot for most fracking operations," Gruber noted.

EcoLogix's Integrated Treatment System offers a holistic approach to wastewater treatment for the oil and gas industry.

The oil and gas industry's increased use of hydraulic fracturing to explore for and produce unconventional oil and gas has made the treatment of produced and flowback water a top concern for the oil and gas industry, environmentalists and the government. 

Between one and five million gallons of water are used in the hydraulic fracturing of one well. The high volume of water used in this process has raised concerns about water resources used in agriculture or drinking water being diverted towards hydraulic fracturing instead, particularly in areas that have or are experiencing drought conditions. The impact on drinking water supplies due in part to the disposal of flowback and produced water, which could contain organic chemicals, metals, salts and naturally occurring radionuclides, is another issue.

To deal with wastewater, oil and gas operators have either injected wastewater into disposal wells or hauled water away by truck. However, some studies have indicated that injecting hydraulic fracturing wastewater injection into disposal wells can trigger earthquakes. A recent study tied a series of earthquakes in central Oklahoma to the injection of wastewater deep underground. Additionally, high salt levels in water can reduce the number and types of organisms found at a site, impacting the entire ecosystem, according to a recent study Australian and European researchers. 

The heavy traffic of trucks hauling wastewater and other materials related to shale exploration and production has resulted in wear and tear on roads around the country. Almost 1,200 loaded trucks are needed to bring one gas well into production, over 350 are required each year for maintaining a gas well, and nearly 1,000 are needed every five years to refracture a well, according to the March 2013 Eagle Ford Shale Task Report. In many places, the existing roads are not equipped to handle the weight and volume of this traffic.

Gruber sees his company's technology as a way to keep both environmentalists and the oil and gas industry happy.

"What appears to be clean may not be clean," Gruber commented, noting that the oil and gas industry's previous attempts to clean water fell short.

By using a short-cut approach, only 20 percent of suspended solids are removed from water, and without a chemical solution, only larger suspended solids will be removed, leaving small suspended particles behind. These smaller  suspended solids, called colloidal, have very large surface area that add friction to the gelling agents and friction reducers, negatively affecting the viscosity of the fluid from carrying the  proppant sand further distances in the water and keep the hydraulic fractures open, impacting the efficacy of a frack job.

Arguments have been made by some in the oil and gas industry that salt must be completely removed from the water to make it suitable for reuse in hydraulic fracturing, Gruber stated that this is simply not the case.

Gruber cited a recent study conducted by Halliburton and XTO Energy and that the level of salt in water does not impact the quality of a hydraulic fracturing job as long as the total suspended solids have been removed. This finding means that oil and gas companies do not have to remove water from aquifers, meaning this water can be saved for agriculture or other purposes.

In the study, Halliburton and XTO found that produced water with total dissolved solids levels as higher 285,000 milligrams per liter, or 28.5 percent salinity, was shown to generate proper cross-linked rheology for hydraulic fracturing in line with wells that were fracturing with just 20,000 particles per million, or 2 percent salinity.

The study results, which were published by the Society of Petroleum Engineers earlier this year, came from a test of seven wells in New Mexico's Delaware Basin. In the field study, a mixture of common drilling chemicals, such as Cacrboxymethyl Hydroxypropyl Guar Gum, a zirconium-based cross linker, sodium chlorite breakers and non-emulsified surfactants were blended with 100 percent treated produced water to generate a frac fluid that performed as well as that expected from a fluid based on fresh water.  

"The study shows that brine water possesses all the characteristics required for effective fracking: easy preparation, rapid hydration, low fluid loss, good proppant transport capacity, low pipe friction, and effective recovery from the reservoir," said Gruber in a recent white paper in regards to the Halliburton-XTO study. "Unlike fresh water, salt water does not restrict oil flow because of an osmotic imbalance that results in clay swelling."

That study also indicated that by using produced water for hydraulic fracturing can help reduce approximately 1,400 truckloads from the roads, and all but eliminate the use of disposal wells. The study delivered $70,000 to $100,000 cost savings per well.

"Removing the suspended solids is the key," Gruber commented. "If you take shortcuts, you compromise the quality of the hydraulic fracturing job."

For this reason, 100 percent brine water can be used for hydraulic fracturing, so long as the suspended solids are removed completely.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

A Balanced Approach to Drilling on Public Lands

**Cross-posted from The Huffington Post**

By Ellis Richard

As a life-long Westerner, and former National Park Service ranger, I’ve spent a lot of time in and around some of America’s most treasured places. I dedicated my career to protecting these parks.

The future of our national parks, and all of the great open spaces of the west is important to me. These powerful American landscapes helped shape our national character, and defined a way of life, and a life style so many of us value. In many ways, these places define America and give meaning and vision to our lives.

With those concerns in mind, this week I took our cause of balanced oil and gas leasing to the Hill and joined the National Parks Conservation Association to brief Congressional offices about our work and the threat fracking and drilling poses to America’s national parks.

I was heartened by what I saw. Staff from more than 30 offices attended to learn about the need to place oil and gas drilling on equal ground with the future of our parks. In fact, it was standing-room-only. This kind of dialogue and interest is progress.

I have been blessed with the opportunity to work and live in communities across the West, from the Grand Tetons in Wyoming, to the Grand Canyon in Arizona, to Dinosaur National Monument in Colorado. It was good to share some of those experiences and see folks paying attention to the need for smarter approach to energy development.

I told those in attendance that we can do this by allowing responsible drilling in the appropriate places, while protecting those treasured landscapes that are part of the American heritage, and an important driver in so many of our local economies.

Energy development and conservation on our public lands is not a zero sum game. There’s a right way and a wrong way to do things. We can achieve balance. For instance, past administrations have protected an acre of public lands for every land leased to oil and gas development. We can achieve that kind of balance if we put our minds to it.

The Obama administration should be planning ahead to allow for drilling in places where it won’t threaten our cultural and natural treasures. But instead, drilling is encroaching on national parks and monuments, including, near Mesa Verde National Park, Dinosaur National Monument, Chaco Canyon National Historic Park, and Pinnacles National Park. This past spring, federal officials in the Colorado office of the Bureau of Land Management wanted to allow drilling rigs right next the visitor center at Dinosaur National Monument.

Just this week, a new poll showed a bipartisan majority of Western voters are more interested in preserving land for recreation and the enjoyment of future generations than in using them for oil and gas drilling. It’s clear from this poll that people living in the west believe that oil and gas production can be done on public lands while also preserving the values of those iconic landscapes we’ve put aside as national parks.

What tourists want to see a drilling rig or take a whiff of gas in the air when they bring their families on vacation? National Parks drive local economies across the United States, especially in the West. National Parks generated $30.1 billion in economic activity each year. Visitors support local hotels, restaurants, stores and outfitters. Our great outdoors in the West also offer an unparalleled quality of life, which is why manufacturing and technological companies relocate there, providing job opportunities.

It’s a simple fact: our communities rely on national parks, and other open spaces to attract high-paying businesses, entrepreneurs and visitors to come to enjoy our world-class recreation resources just as much as we rely on energy development — done responsibly, in appropriate places. There are some places too special to drill.

Energy development on our public lands also provides economic benefits to our Western communities by creating jobs and providing American energy. I believe we can extract oil and gas responsibly from public lands and also provide the protection national parks need and deserve with a balanced approach to leasing.

My fellow rangers and I at Park Rangers for Our Lands believe we need to “look before we lease” our public lands to oil and gas development. If we take the time and do the work to plan ahead, we can stop problems before they start and protect the future of our parks.

We know some of these solutions will be hard to find, but that doesn’t mean we can just give up. We need the BLM and the National Park Service to work together to do the responsible planning needed to preserve the landscapes that can affect the values of the parks we have worked hard to set aside. If they will do the landscape level planning, we can safeguard those sensitive lands around the national park. It’s a balanced and reasonable alternative that extends protection to our parks while developing the energy resources our country needs.

View the original article here

Plexus Brings New Engineering Approach to Wellhead Technology

UK-based Plexus Ocean Systems Ltd., a division of Plexus Holdings plc, is utilizing a patented technology that the company believes will improve wellhead design to prevent or minimize the impact of blowouts such as the April 2010 Macondo incident in the Gulf of Mexico and the 2009 Montara blowout offshore Australia.

The company's POS-GRIP technology, invented by the company's CEO and founder Ben Van Bilderbeek employs a method of elastically deflecting an outer wellhead body onto an inner casing or tubing hanger and locking them in place to support tubular weight and activate seals. In surface wellhead applications, the system is powered by reusable hydraulic devices, which are fitted temporarily to flanges on the outside of the wellhead.

An example of a POS-GRIP Rotary Surface Wellhead

Van Bilderbeek said he sees friction-grip technology as the best available and safest (BAST) method of engineering for wellheads for all applications, including:

Exploration wellheadsProduction wellheadsTie-back wellheadsDeepwater dry tree wellheadsSurface blowout preventer (BOP) wellhead systemsWorkover wellheadsGeothermal wellheadsFracking technologyCO2 storage wellheads

POS-GRIP technology has been used for 12 years in the North Sea, particularly for high-pressure, high-temperature (HP/HT) wells, Van Bilderbeek told Rigzone.

The technology was initially introduced in the North Sea through an adjustable rental wellhead system for jackup drilling operations; later, POS-GRIP technology was developed for use in specialized HP/HT wellhead systems.

Plexus hopes to replicate the success of its HP/HT technology in the larger international production wellhead and subsea arenas as company officials see many applications in unconventional fields.

The company has had discussions with a number of companies to license POS-GRIP technology, and would like to enter the U.S. market with a partner, or potentially sell certain applications that don't fit perfectly with Plexus' business strategy.

"We ourselves are not interested in operating in the U.S. due to the risk factors that apply in U.S. waters," said Van Bilderbeek. There are lots of targets around the world with less risk."

POS-GRIP technology presents a number of advantages over existing spool-type and mandrel hanger wellhead technologies, depending on the application, including:

Installation of hangers through the BOPShorter time for installationRigid assemblyMultiple metal seals over a large contact areas, for a corrosion resistant designIntegral seal design to minimize the number of leak pathsSingle component hangers

The technology also offers superior reliability, reduced life cycle cost and is tolerant to a contaminated environment.

The company's roster of customers includes: Apache Corp., BHP Billiton Ltd., BP Plc, ConocoPhillips Company, Maersk Oil, Lundin Petroleum AB, Newfield Exploration Company, Talisman Energy Inc., Statoil, Royal Dutch Shell Plc, Total S.A. and Wintershall Holding GmbH.

"Recent well control incidents around the world have highlighted the need for robust, high performance, subsea wellheads in oil and gas operations, particularly in extreme and hostile environments," said Van Bilderbeek in a June 19, 2012 statement.

"Specific functionality is required such as instant casing hanger lockdown, the ability to monitor sustained casing pressure and then enable remedial action and bleed off capability."

An example of how the POS-GRIP mechanism works

The company has designed wellheads to be the strong link in the well system, Van Bilderbeek noted in a presentation for U.S. government officials in December 2012, and is pursuing a policy of preventing blowouts "by design". Achieving the goal of wellheads as the strong link includes matching wellhead standards to those for casing and tubing couplings, Van Bilderbeek noted.

To prevent blowouts, the company argues that the industry needs to eliminate the practice of lifting BOPs from the wellhead to set casing. Wellheads must be designed to be permanent safe platforms for well control devices, while maintaining dual barriers across the well bore and annular spaces adhered to at all times.

Additionally wellhead designs where possible should rely on rigid metal sealing for integrity beyond field life, and such standards should apply to all applications, rather than just for HP/HT wells.

Van Bilderbeek pointed out that current wellhead qualification test procedures are component based, whereas emerging standards require specific qualification tests treating seals as part of a system. Currently, standards for casing and tubing couplings are far more stringent than for wellheads.

Most blowouts occur when the BOPs are away from the wellhead, as American Petroleum Institute (API) spool type systems require removal of the BOPs to set casing.

One justification for continuing the century old habit of lifting BOPs is that this method eliminates to need to space out casing, avoiding the extra work of measuring pipe into ground.

"Further excuses include the need to tension casing, which is negated by the fact that this can be done with through BOP technology," Van Bilderbeek noted.

There is no longer any justification for ever designing wellheads that require the lifting of BOPs to be set casing, as without a BOP in place a well is left under the sole protection of single barriers for an extended period of time.

The Montara Commission of Inquiry Report links the design of pressure containing corrosion caps to the Montara incident, adding that removing abandonment caps from the well before a riser with a well control device on top is re-established clearly breaks the dual barrier rule, Van Bilderbeek noted.

The United States' forerunner agency to the Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement (BSEE), the U.S. Minerals Management Services had recognized the risk of lifting BOPs; they proposed a solution to improve cementing techniques, as seen in an incident that occurred in April 1997 at East Cameron Block 328. On that day, a serious blowout and fire occurred on Platform A. The U.S. Department of the Interior (DOI) concluded the probable cause of the incident was formation gas migrating through the cement between the 9-5/8-inch casing and the 13-3/8-inch casing.

DOI officials also concluded there was not enough wait-on-cement time prior to nippling down the BOP. A possible contributing cause was that, since the well had been drilled horizontal, the casing may not have been properly centralized, resulting in a non-uniform cement job.

Plexus' solution would be to require that the BOPs be left in place by using thru-BOP wellhead technology, which is available from all major suppliers. This allows an operator to control a well-kick during casing installation procedures.

Van Bilderbeek believes the industry would benefit from a wider acceptance of the simple and obvious BAST rule -- never lift BOPs unless absolutely necessary.

When a POS-GRIP wellhead is activated, multiple metal seals interact over a long interface between the wellhead bore and casing hanger. Conventional annular seal are no longer required, and movement between parts is eliminated for integrity beyond field life. Qualification has taken place under simulated and extended field life testing conditions, Plexus officials noted.

In subsea wellhead applications, the technical solutions available to lock and seal casing and tubing annuli have been problematic. As a direct consequence, the industry has adopted a procedure of installing lock-down sleeves to fix casing hangers in the well bore at the end of the drilling program.

These devices, which are time consuming and can cost between an estimated $2 million and $5 million to install, are used because of the problems associated with using remotely activated lock-ring devices in the contaminated environment of a subsea well.

To be functional, a lockdown sleeve needs to be set with downward load on the casing hangers. The length of the weight string of pipe hanging from below a lockdown sleeve can dictate the setting depth for the cement plug, depending on the chosen installation sequence, van Bilderbeek noted.

If mud is replaced with seawater prior to setting of the cement plug, its setting depth can contribute to under-balancing of the well, which suggests that the use of a lockdown sleeve to secure casing hangers in a subsea wellhead, because conventional lockdown devices are problematic, can lead to well control incidents.

"Conversely, on surface wellhead applications, all casing hangers are individually locked down as soon as casing is cemented, and this is done for good reason," Van Bilderbeek noted, and the same logic and safety disciplines should apply subsea for the protection of personnel and the environment.

Van Bilderbeek noted that DOI's May 2010 report advising that all casing hangers should be instantly locked down following cementing is correct.

Van Bilderbeek, who met with U.S. government officials in early December 2012 as part of a teaching mission on technology available for wellhead design, and to highlight the conflict which comes into play when a technology is both BAST and proprietary, notes that no justification exists for ever leaving casing hangers unlocked in a subsea wellhead at any time during drilling or production.

Van Bilderbeek commented that Shell has issued revised qualification guidelines which require that the lockdown capacity for subsea casing hangers during drilling is proven to a level equivalent to the requirement for production casing hangers in the field, Van Bilderbeek noted.

A POS-GRIP HG Platform Wellhead System

In October 2010, a joint industry project (JIP) was formed by Plexus to focus on development of a new class of subsea wellhead system, the POS-GRIP HGSS subsea wellhead, with particular focus on addressing systemic deficiencies of current technology. The JIP's primary target is to design a wellhead system in which all casing hangers can achieve rigid lockdown following cementing, while remaining releasable if it becomes necessary to recover casing.

The JIP's member rosters now include ENI, Oil States Industries, Maersk Oil subsidiary Maersk Oil North Sea UK, Shell Plc subsidiary Shell International Exploration and Production, Wintershall Holdings GmbH subsidiary Wintershall Noordzee, Total S.A., and Tullow Oil Plc. The project is expected to take between 18 and 24 months from the February 2012 launch date at a cost of approximately $2.3 million to $3.1 million (GBP 1.5 million to GBP 2 million). Any intellectual property created through the JIP will be owned by Plexus.

Key features that Plexus hopes to incorporate into its new POS-GRIP HGSS subsea wellhead design include:

18-3/4-inch full bore system, rated to 15,000 per square inch (psi) and 350 degrees FahrenheitAbility to upgrade to 20,000 psi, 450 degrees Fahrenheit4 million pounds of "instant" casing hanger lockdown capacityAvoidance of acknowledged problems associated with using lock down ringsAnnulus monitoring and bleed-off capability to address sustained casing pressure situations, with diagnostic and remedial capabilityAbility to open and reseal the casing annulus to enable remedial cement job proceduresRigid metal annular seal technology qualified to match the standards for premium casing couplingsMeeting the API 17/D/ISO 13628-4 requirements, recently provided operator requirements, and Plexus Life Cycle Testing

The wellhead standards utilized by the Plexus JIP will be more stringent than those proposed by API for similar technology, Van Bilderbeek commented.

The Plexus wellhead standard will be pitched to match the standards required of premium casing and tubing couplings. Van Bilderbeek noted that this is not the approach that API currently takes by allowing a single sample test, and unlimited number of attempts.

The Plexus JIP also requires make and break testing, test to failure, simulate field conditions, and test under loading, Van Bilderbeek noted.

BSEE has identified the need for development work on 20,000 psi extreme HP/HT subsea drilling equipment and well design. However, Van Bilderbeek pointed out that a recent BSEE report fails to address systemic shortcomings of conventional 15,000 psi and below applications, focusing only on work to be done in the 20,000 psi and above category.

The BSEE has reported that additional developments and qualified work will be required before 20,000 psi systems are commercially available for subsea applications. For 20,000 psi drilling equipment, the current direction is the development of custom products. Wellhead systems with working pressures in excess of 15,000 psi are under development and not expected to be ready for use for a number of years.

Van Bilderbeek reported that the HGSS wellhead technology design work is underway, based on qualified hanger designs used on 20,000 psi surface drilling operations in the North Sea.

Testing on the HGSS JIP to adapt POS-GRIP technology for subsea applications is well advanced, and a POS-GRIP HP/HT tie-back connector designed to allow operators to pre-drill HP/HT production wells is now available.

Plexus believes POS-GRIP's potential in its HP/HT tieback application is one of the most far reaching developments in many years. According to Plexus, HP/HT and ultra high-pressure/high-temperature (XHP/XHT) wells could be safely tied back at a future date, negating the disposable nature of these wells.

Potential savings for the operator is the entire cost of the well, which Plexus estimates is between $75 million to $450 million per HP/HT well, and the well can begin to generate revenues at a much earlier date. HP/HT wells in a proven field could be pre-drilled and abandoned ready for completion while the platform was being designed and construction.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Plexus Brings New Engineering Approach to Wellhead Technology

UK-based Plexus Ocean Systems Ltd., a division of Plexus Holdings plc, is utilizing a patented technology that the company believes will improve wellhead design to prevent or minimize the impact of blowouts such as the April 2010 Macondo incident in the Gulf of Mexico and the 2009 Montara blowout offshore Australia.

The company's POS-GRIP technology, invented by the company's CEO and founder Ben Van Bilderbeek employs a method of elastically deflecting an outer wellhead body onto an inner casing or tubing hanger and locking them in place to support tubular weight and activate seals. In surface wellhead applications, the system is powered by reusable hydraulic devices, which are fitted temporarily to flanges on the outside of the wellhead.

An example of a POS-GRIP Rotary Surface Wellhead

Van Bilderbeek said he sees friction-grip technology as the best available and safest (BAST) method of engineering for wellheads for all applications, including:

Exploration wellheadsProduction wellheadsTie-back wellheadsDeepwater dry tree wellheadsSurface blowout preventer (BOP) wellhead systemsWorkover wellheadsGeothermal wellheadsFracking technologyCO2 storage wellheads

POS-GRIP technology has been used for 12 years in the North Sea, particularly for high-pressure, high-temperature (HP/HT) wells, Van Bilderbeek told Rigzone.

The technology was initially introduced in the North Sea through an adjustable rental wellhead system for jackup drilling operations; later, POS-GRIP technology was developed for use in specialized HP/HT wellhead systems.

Plexus hopes to replicate the success of its HP/HT technology in the larger international production wellhead and subsea arenas as company officials see many applications in unconventional fields.

The company has had discussions with a number of companies to license POS-GRIP technology, and would like to enter the U.S. market with a partner, or potentially sell certain applications that don't fit perfectly with Plexus' business strategy.

"We ourselves are not interested in operating in the U.S. due to the risk factors that apply in U.S. waters," said Van Bilderbeek. There are lots of targets around the world with less risk."

POS-GRIP technology presents a number of advantages over existing spool-type and mandrel hanger wellhead technologies, depending on the application, including:

Installation of hangers through the BOPShorter time for installationRigid assemblyMultiple metal seals over a large contact areas, for a corrosion resistant designIntegral seal design to minimize the number of leak pathsSingle component hangers

The technology also offers superior reliability, reduced life cycle cost and is tolerant to a contaminated environment.

The company's roster of customers includes: Apache Corp., BHP Billiton Ltd., BP Plc, ConocoPhillips Company, Maersk Oil, Lundin Petroleum AB, Newfield Exploration Company, Talisman Energy Inc., Statoil, Royal Dutch Shell Plc, Total S.A. and Wintershall Holding GmbH.

"Recent well control incidents around the world have highlighted the need for robust, high performance, subsea wellheads in oil and gas operations, particularly in extreme and hostile environments," said Van Bilderbeek in a June 19, 2012 statement.

"Specific functionality is required such as instant casing hanger lockdown, the ability to monitor sustained casing pressure and then enable remedial action and bleed off capability."

An example of how the POS-GRIP mechanism works

The company has designed wellheads to be the strong link in the well system, Van Bilderbeek noted in a presentation for U.S. government officials in December 2012, and is pursuing a policy of preventing blowouts "by design". Achieving the goal of wellheads as the strong link includes matching wellhead standards to those for casing and tubing couplings, Van Bilderbeek noted.

To prevent blowouts, the company argues that the industry needs to eliminate the practice of lifting BOPs from the wellhead to set casing. Wellheads must be designed to be permanent safe platforms for well control devices, while maintaining dual barriers across the well bore and annular spaces adhered to at all times.

Additionally wellhead designs where possible should rely on rigid metal sealing for integrity beyond field life, and such standards should apply to all applications, rather than just for HP/HT wells.

Van Bilderbeek pointed out that current wellhead qualification test procedures are component based, whereas emerging standards require specific qualification tests treating seals as part of a system. Currently, standards for casing and tubing couplings are far more stringent than for wellheads.

Most blowouts occur when the BOPs are away from the wellhead, as American Petroleum Institute (API) spool type systems require removal of the BOPs to set casing.

One justification for continuing the century old habit of lifting BOPs is that this method eliminates to need to space out casing, avoiding the extra work of measuring pipe into ground.

"Further excuses include the need to tension casing, which is negated by the fact that this can be done with through BOP technology," Van Bilderbeek noted.

There is no longer any justification for ever designing wellheads that require the lifting of BOPs to be set casing, as without a BOP in place a well is left under the sole protection of single barriers for an extended period of time.

The Montara Commission of Inquiry Report links the design of pressure containing corrosion caps to the Montara incident, adding that removing abandonment caps from the well before a riser with a well control device on top is re-established clearly breaks the dual barrier rule, Van Bilderbeek noted.

The United States' forerunner agency to the Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement (BSEE), the U.S. Minerals Management Services had recognized the risk of lifting BOPs; they proposed a solution to improve cementing techniques, as seen in an incident that occurred in April 1997 at East Cameron Block 328. On that day, a serious blowout and fire occurred on Platform A. The U.S. Department of the Interior (DOI) concluded the probable cause of the incident was formation gas migrating through the cement between the 9-5/8-inch casing and the 13-3/8-inch casing.

DOI officials also concluded there was not enough wait-on-cement time prior to nippling down the BOP. A possible contributing cause was that, since the well had been drilled horizontal, the casing may not have been properly centralized, resulting in a non-uniform cement job.

Plexus' solution would be to require that the BOPs be left in place by using thru-BOP wellhead technology, which is available from all major suppliers. This allows an operator to control a well-kick during casing installation procedures.

Van Bilderbeek believes the industry would benefit from a wider acceptance of the simple and obvious BAST rule -- never lift BOPs unless absolutely necessary.

When a POS-GRIP wellhead is activated, multiple metal seals interact over a long interface between the wellhead bore and casing hanger. Conventional annular seal are no longer required, and movement between parts is eliminated for integrity beyond field life. Qualification has taken place under simulated and extended field life testing conditions, Plexus officials noted.

In subsea wellhead applications, the technical solutions available to lock and seal casing and tubing annuli have been problematic. As a direct consequence, the industry has adopted a procedure of installing lock-down sleeves to fix casing hangers in the well bore at the end of the drilling program.

These devices, which are time consuming and can cost between an estimated $2 million and $5 million to install, are used because of the problems associated with using remotely activated lock-ring devices in the contaminated environment of a subsea well.

To be functional, a lockdown sleeve needs to be set with downward load on the casing hangers. The length of the weight string of pipe hanging from below a lockdown sleeve can dictate the setting depth for the cement plug, depending on the chosen installation sequence, van Bilderbeek noted.

If mud is replaced with seawater prior to setting of the cement plug, its setting depth can contribute to under-balancing of the well, which suggests that the use of a lockdown sleeve to secure casing hangers in a subsea wellhead, because conventional lockdown devices are problematic, can lead to well control incidents.

"Conversely, on surface wellhead applications, all casing hangers are individually locked down as soon as casing is cemented, and this is done for good reason," Van Bilderbeek noted, and the same logic and safety disciplines should apply subsea for the protection of personnel and the environment.

Van Bilderbeek noted that DOI's May 2010 report advising that all casing hangers should be instantly locked down following cementing is correct.

Van Bilderbeek, who met with U.S. government officials in early December 2012 as part of a teaching mission on technology available for wellhead design, and to highlight the conflict which comes into play when a technology is both BAST and proprietary, notes that no justification exists for ever leaving casing hangers unlocked in a subsea wellhead at any time during drilling or production.

Van Bilderbeek commented that Shell has issued revised qualification guidelines which require that the lockdown capacity for subsea casing hangers during drilling is proven to a level equivalent to the requirement for production casing hangers in the field, Van Bilderbeek noted.

A POS-GRIP HG Platform Wellhead System

In October 2010, a joint industry project (JIP) was formed by Plexus to focus on development of a new class of subsea wellhead system, the POS-GRIP HGSS subsea wellhead, with particular focus on addressing systemic deficiencies of current technology. The JIP's primary target is to design a wellhead system in which all casing hangers can achieve rigid lockdown following cementing, while remaining releasable if it becomes necessary to recover casing.

The JIP's member rosters now include ENI, Oil States Industries, Maersk Oil subsidiary Maersk Oil North Sea UK, Shell Plc subsidiary Shell International Exploration and Production, Wintershall Holdings GmbH subsidiary Wintershall Noordzee, Total S.A., and Tullow Oil Plc. The project is expected to take between 18 and 24 months from the February 2012 launch date at a cost of approximately $2.3 million to $3.1 million (GBP 1.5 million to GBP 2 million). Any intellectual property created through the JIP will be owned by Plexus.

Key features that Plexus hopes to incorporate into its new POS-GRIP HGSS subsea wellhead design include:

18-3/4-inch full bore system, rated to 15,000 per square inch (psi) and 350 degrees FahrenheitAbility to upgrade to 20,000 psi, 450 degrees Fahrenheit4 million pounds of "instant" casing hanger lockdown capacityAvoidance of acknowledged problems associated with using lock down ringsAnnulus monitoring and bleed-off capability to address sustained casing pressure situations, with diagnostic and remedial capabilityAbility to open and reseal the casing annulus to enable remedial cement job proceduresRigid metal annular seal technology qualified to match the standards for premium casing couplingsMeeting the API 17/D/ISO 13628-4 requirements, recently provided operator requirements, and Plexus Life Cycle Testing

The wellhead standards utilized by the Plexus JIP will be more stringent than those proposed by API for similar technology, Van Bilderbeek commented.

The Plexus wellhead standard will be pitched to match the standards required of premium casing and tubing couplings. Van Bilderbeek noted that this is not the approach that API currently takes by allowing a single sample test, and unlimited number of attempts.

The Plexus JIP also requires make and break testing, test to failure, simulate field conditions, and test under loading, Van Bilderbeek noted.

BSEE has identified the need for development work on 20,000 psi extreme HP/HT subsea drilling equipment and well design. However, Van Bilderbeek pointed out that a recent BSEE report fails to address systemic shortcomings of conventional 15,000 psi and below applications, focusing only on work to be done in the 20,000 psi and above category.

The BSEE has reported that additional developments and qualified work will be required before 20,000 psi systems are commercially available for subsea applications. For 20,000 psi drilling equipment, the current direction is the development of custom products. Wellhead systems with working pressures in excess of 15,000 psi are under development and not expected to be ready for use for a number of years.

Van Bilderbeek reported that the HGSS wellhead technology design work is underway, based on qualified hanger designs used on 20,000 psi surface drilling operations in the North Sea.

Testing on the HGSS JIP to adapt POS-GRIP technology for subsea applications is well advanced, and a POS-GRIP HP/HT tie-back connector designed to allow operators to pre-drill HP/HT production wells is now available.

Plexus believes POS-GRIP's potential in its HP/HT tieback application is one of the most far reaching developments in many years. According to Plexus, HP/HT and ultra high-pressure/high-temperature (XHP/XHT) wells could be safely tied back at a future date, negating the disposable nature of these wells.

Potential savings for the operator is the entire cost of the well, which Plexus estimates is between $75 million to $450 million per HP/HT well, and the well can begin to generate revenues at a much earlier date. HP/HT wells in a proven field could be pre-drilled and abandoned ready for completion while the platform was being designed and construction.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Plexus Brings New Engineering Approach to Wellhead Technology

UK-based Plexus Ocean Systems Ltd., a division of Plexus Holdings plc, is utilizing a patented technology that the company believes will improve wellhead design to prevent or minimize the impact of blowouts such as the April 2010 Macondo incident in the Gulf of Mexico and the 2009 Montara blowout offshore Australia.

The company's POS-GRIP technology, invented by the company's CEO and founder Ben Van Bilderbeek employs a method of elastically deflecting an outer wellhead body onto an inner casing or tubing hanger and locking them in place to support tubular weight and activate seals. In surface wellhead applications, the system is powered by reusable hydraulic devices, which are fitted temporarily to flanges on the outside of the wellhead.

An example of a POS-GRIP Rotary Surface Wellhead

Van Bilderbeek said he sees friction-grip technology as the best available and safest (BAST) method of engineering for wellheads for all applications, including:

Exploration wellheadsProduction wellheadsTie-back wellheadsDeepwater dry tree wellheadsSurface blowout preventer (BOP) wellhead systemsWorkover wellheadsGeothermal wellheadsFracking technologyCO2 storage wellheads

POS-GRIP technology has been used for 12 years in the North Sea, particularly for high-pressure, high-temperature (HP/HT) wells, Van Bilderbeek told Rigzone.

The technology was initially introduced in the North Sea through an adjustable rental wellhead system for jackup drilling operations; later, POS-GRIP technology was developed for use in specialized HP/HT wellhead systems.

Plexus hopes to replicate the success of its HP/HT technology in the larger international production wellhead and subsea arenas as company officials see many applications in unconventional fields.

The company has had discussions with a number of companies to license POS-GRIP technology, and would like to enter the U.S. market with a partner, or potentially sell certain applications that don't fit perfectly with Plexus' business strategy.

"We ourselves are not interested in operating in the U.S. due to the risk factors that apply in U.S. waters," said Van Bilderbeek. There are lots of targets around the world with less risk."

POS-GRIP technology presents a number of advantages over existing spool-type and mandrel hanger wellhead technologies, depending on the application, including:

Installation of hangers through the BOPShorter time for installationRigid assemblyMultiple metal seals over a large contact areas, for a corrosion resistant designIntegral seal design to minimize the number of leak pathsSingle component hangers

The technology also offers superior reliability, reduced life cycle cost and is tolerant to a contaminated environment.

The company's roster of customers includes: Apache Corp., BHP Billiton Ltd., BP Plc, ConocoPhillips Company, Maersk Oil, Lundin Petroleum AB, Newfield Exploration Company, Talisman Energy Inc., Statoil, Royal Dutch Shell Plc, Total S.A. and Wintershall Holding GmbH.

"Recent well control incidents around the world have highlighted the need for robust, high performance, subsea wellheads in oil and gas operations, particularly in extreme and hostile environments," said Van Bilderbeek in a June 19, 2012 statement.

"Specific functionality is required such as instant casing hanger lockdown, the ability to monitor sustained casing pressure and then enable remedial action and bleed off capability."

An example of how the POS-GRIP mechanism works

The company has designed wellheads to be the strong link in the well system, Van Bilderbeek noted in a presentation for U.S. government officials in December 2012, and is pursuing a policy of preventing blowouts "by design". Achieving the goal of wellheads as the strong link includes matching wellhead standards to those for casing and tubing couplings, Van Bilderbeek noted.

To prevent blowouts, the company argues that the industry needs to eliminate the practice of lifting BOPs from the wellhead to set casing. Wellheads must be designed to be permanent safe platforms for well control devices, while maintaining dual barriers across the well bore and annular spaces adhered to at all times.

Additionally wellhead designs where possible should rely on rigid metal sealing for integrity beyond field life, and such standards should apply to all applications, rather than just for HP/HT wells.

Van Bilderbeek pointed out that current wellhead qualification test procedures are component based, whereas emerging standards require specific qualification tests treating seals as part of a system. Currently, standards for casing and tubing couplings are far more stringent than for wellheads.

Most blowouts occur when the BOPs are away from the wellhead, as American Petroleum Institute (API) spool type systems require removal of the BOPs to set casing.

One justification for continuing the century old habit of lifting BOPs is that this method eliminates to need to space out casing, avoiding the extra work of measuring pipe into ground.

"Further excuses include the need to tension casing, which is negated by the fact that this can be done with through BOP technology," Van Bilderbeek noted.

There is no longer any justification for ever designing wellheads that require the lifting of BOPs to be set casing, as without a BOP in place a well is left under the sole protection of single barriers for an extended period of time.

The Montara Commission of Inquiry Report links the design of pressure containing corrosion caps to the Montara incident, adding that removing abandonment caps from the well before a riser with a well control device on top is re-established clearly breaks the dual barrier rule, Van Bilderbeek noted.

The United States' forerunner agency to the Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement (BSEE), the U.S. Minerals Management Services had recognized the risk of lifting BOPs; they proposed a solution to improve cementing techniques, as seen in an incident that occurred in April 1997 at East Cameron Block 328. On that day, a serious blowout and fire occurred on Platform A. The U.S. Department of the Interior (DOI) concluded the probable cause of the incident was formation gas migrating through the cement between the 9-5/8-inch casing and the 13-3/8-inch casing.

DOI officials also concluded there was not enough wait-on-cement time prior to nippling down the BOP. A possible contributing cause was that, since the well had been drilled horizontal, the casing may not have been properly centralized, resulting in a non-uniform cement job.

Plexus' solution would be to require that the BOPs be left in place by using thru-BOP wellhead technology, which is available from all major suppliers. This allows an operator to control a well-kick during casing installation procedures.

Van Bilderbeek believes the industry would benefit from a wider acceptance of the simple and obvious BAST rule -- never lift BOPs unless absolutely necessary.

When a POS-GRIP wellhead is activated, multiple metal seals interact over a long interface between the wellhead bore and casing hanger. Conventional annular seal are no longer required, and movement between parts is eliminated for integrity beyond field life. Qualification has taken place under simulated and extended field life testing conditions, Plexus officials noted.

In subsea wellhead applications, the technical solutions available to lock and seal casing and tubing annuli have been problematic. As a direct consequence, the industry has adopted a procedure of installing lock-down sleeves to fix casing hangers in the well bore at the end of the drilling program.

These devices, which are time consuming and can cost between an estimated $2 million and $5 million to install, are used because of the problems associated with using remotely activated lock-ring devices in the contaminated environment of a subsea well.

To be functional, a lockdown sleeve needs to be set with downward load on the casing hangers. The length of the weight string of pipe hanging from below a lockdown sleeve can dictate the setting depth for the cement plug, depending on the chosen installation sequence, van Bilderbeek noted.

If mud is replaced with seawater prior to setting of the cement plug, its setting depth can contribute to under-balancing of the well, which suggests that the use of a lockdown sleeve to secure casing hangers in a subsea wellhead, because conventional lockdown devices are problematic, can lead to well control incidents.

"Conversely, on surface wellhead applications, all casing hangers are individually locked down as soon as casing is cemented, and this is done for good reason," Van Bilderbeek noted, and the same logic and safety disciplines should apply subsea for the protection of personnel and the environment.

Van Bilderbeek noted that DOI's May 2010 report advising that all casing hangers should be instantly locked down following cementing is correct.

Van Bilderbeek, who met with U.S. government officials in early December 2012 as part of a teaching mission on technology available for wellhead design, and to highlight the conflict which comes into play when a technology is both BAST and proprietary, notes that no justification exists for ever leaving casing hangers unlocked in a subsea wellhead at any time during drilling or production.

Van Bilderbeek commented that Shell has issued revised qualification guidelines which require that the lockdown capacity for subsea casing hangers during drilling is proven to a level equivalent to the requirement for production casing hangers in the field, Van Bilderbeek noted.

A POS-GRIP HG Platform Wellhead System

In October 2010, a joint industry project (JIP) was formed by Plexus to focus on development of a new class of subsea wellhead system, the POS-GRIP HGSS subsea wellhead, with particular focus on addressing systemic deficiencies of current technology. The JIP's primary target is to design a wellhead system in which all casing hangers can achieve rigid lockdown following cementing, while remaining releasable if it becomes necessary to recover casing.

The JIP's member rosters now include ENI, Oil States Industries, Maersk Oil subsidiary Maersk Oil North Sea UK, Shell Plc subsidiary Shell International Exploration and Production, Wintershall Holdings GmbH subsidiary Wintershall Noordzee, Total S.A., and Tullow Oil Plc. The project is expected to take between 18 and 24 months from the February 2012 launch date at a cost of approximately $2.3 million to $3.1 million (GBP 1.5 million to GBP 2 million). Any intellectual property created through the JIP will be owned by Plexus.

Key features that Plexus hopes to incorporate into its new POS-GRIP HGSS subsea wellhead design include:

18-3/4-inch full bore system, rated to 15,000 per square inch (psi) and 350 degrees FahrenheitAbility to upgrade to 20,000 psi, 450 degrees Fahrenheit4 million pounds of "instant" casing hanger lockdown capacityAvoidance of acknowledged problems associated with using lock down ringsAnnulus monitoring and bleed-off capability to address sustained casing pressure situations, with diagnostic and remedial capabilityAbility to open and reseal the casing annulus to enable remedial cement job proceduresRigid metal annular seal technology qualified to match the standards for premium casing couplingsMeeting the API 17/D/ISO 13628-4 requirements, recently provided operator requirements, and Plexus Life Cycle Testing

The wellhead standards utilized by the Plexus JIP will be more stringent than those proposed by API for similar technology, Van Bilderbeek commented.

The Plexus wellhead standard will be pitched to match the standards required of premium casing and tubing couplings. Van Bilderbeek noted that this is not the approach that API currently takes by allowing a single sample test, and unlimited number of attempts.

The Plexus JIP also requires make and break testing, test to failure, simulate field conditions, and test under loading, Van Bilderbeek noted.

BSEE has identified the need for development work on 20,000 psi extreme HP/HT subsea drilling equipment and well design. However, Van Bilderbeek pointed out that a recent BSEE report fails to address systemic shortcomings of conventional 15,000 psi and below applications, focusing only on work to be done in the 20,000 psi and above category.

The BSEE has reported that additional developments and qualified work will be required before 20,000 psi systems are commercially available for subsea applications. For 20,000 psi drilling equipment, the current direction is the development of custom products. Wellhead systems with working pressures in excess of 15,000 psi are under development and not expected to be ready for use for a number of years.

Van Bilderbeek reported that the HGSS wellhead technology design work is underway, based on qualified hanger designs used on 20,000 psi surface drilling operations in the North Sea.

Testing on the HGSS JIP to adapt POS-GRIP technology for subsea applications is well advanced, and a POS-GRIP HP/HT tie-back connector designed to allow operators to pre-drill HP/HT production wells is now available.

Plexus believes POS-GRIP's potential in its HP/HT tieback application is one of the most far reaching developments in many years. According to Plexus, HP/HT and ultra high-pressure/high-temperature (XHP/XHT) wells could be safely tied back at a future date, negating the disposable nature of these wells.

Potential savings for the operator is the entire cost of the well, which Plexus estimates is between $75 million to $450 million per HP/HT well, and the well can begin to generate revenues at a much earlier date. HP/HT wells in a proven field could be pre-drilled and abandoned ready for completion while the platform was being designed and construction.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments are subject to editorial review. Off-topic, inappropriate or insulting comments will be removed.

View the original article here

Raising Energy Taxes – The Wrong Approach

Update: The U.S. Senate failed to reach the 60 votes needed to invoke cloture and the motion failed 51-47. (29 Mar 2012)

Today the Senate will vote to advance S.2204 sponsored by Sen. Menendez (D-NJ). This bill will raise taxes on major integrated oil and natural gas companies to subsidize other forms of energy and will do absolutely nothing to lower gasoline prices.

A new poll conducted by Harris Interactive, from March 9-13 of registered voters nationwide, found that 76% of voters believe that increasing energy taxes could increase consumer costs on a wide variety of products, including higher gasoline prices.

American voters overwhelming oppose higher taxes!

Additionally, this bill claims to end alleged “subsidies” for a handful of oil and natural gas companies. However, nothing could be further from the truth. The U.S. oil and natural gas industry does not receive “subsidized” payments from the government to produce oil and gas. In fact, the Wall Street Journal editorial board states “the truth is that this industry is subsidizing the government.” The US oil and natural gas industry on average pays over $86 million every day to the federal government in taxes, rents, royalties and lease payments.

U.S. oil and natural gas companies pay considerably more of its profits in taxes than the average manufacturing company. In fact, in 2010, the industry paid more in total taxes than any other industry sector while averaging a 41% effective tax rate. Also in 2010, oil and natural gas companies directly contributed over $470 billion to the U.S. economy in spending, wages, and dividends – more than half the size of the 2009 federal stimulus package ($787 billion) – only this stimulus didn’t require an act of Congress.

Below are more details on the specific negative effects of the tax provisions that are included in the Menendez bill:

Dual Capacity/Foreign Tax Credit denial: API’s one pager discussing how this will make American companies uncompetitive abroad is here and there are more in-depth studies on this topic here, here and here. Despite rhetoric, the provision they seek to modify ironically is a more stringent rule on taxpayers like the oil and gas industry that has, for the last 3 decades, ensured abuses do not occur. The foreign tax credit can only be used to offset foreign income taxes paid and not any other payment. Without this foreign tax credit, which has been in place since 1918, US-based companies would be substantially disadvantaged when trying to develop foreign opportunities. Specifically, companies would face the cost of double taxation on foreign operations, while their competitors would only be taxed once.Sec. 199 repeal: Section 199 is available to every single domestic manufacturer and extractive industry that qualifies and is in no way unique to the oil and gas industry. As seen here, the oil and gas industry is already penalized with respect to others as we receive a 6% deduction on income from qualified activities; everyone else receives a 9% deduction. This provision was put into place in the American Jobs Creation Act in 2004 to create and keep jobs in the U.S. – exactly what we are doing. We support 9.2 million jobs in the U.S. and contribute to 7.7% of GDP. By removing this provision from just a handful of companies it sends the message a job in the oil and gas industry is not as “valuable” as a job at Starbucks or the New York Times (both of whom get 199 at 9%). Studies have shown repealing Sec. 199 (and IDC below) for the entire industry could put 165,000 direct/indirect jobs at risk by 2020.Repeal of drilling cost deduction (IDCs): Just like the R&D deduction (comparison here) our companies can deduct costs associated with the labor and construction of a well. As you can see in this one-pager, these costs, typically 60-80% of the cost of a well, are simply cost recovery with respect to timing – there is no credit or government subsidy here. Cost recovery allows us to put that money back into projects, technology and high wages. The average upstream wage is approx $98,000/yr. This provision is not unique to the Code and could compromise thousands of jobs and billions of dollars worth of capital – in fact, this repeal along with (Sec. 199 above) could compromise 10% of America’s oil and gas production capacity by 2017.Percentage depletion: The major integrated US oil and gas companies (the target of this amendment) are not eligible for percentage depletion and have not been for over 30 years. IPAA has more on how this affects independent producers.Repeal of tertiary injectant deduction: The U.S. is a mature oil producing region but still contains many viable fields whose lives are extended through the use of tertiary injectants. These efforts secure additional U.S. production and enable many production companies to remain in business. Changing how these costs are recovered could force producers to shut in older fields and significantly impact local economies. This deduction supports using carbon dioxide in enhanced oil recovery projects, one of the primary methods by which carbon dioxide is currently stored to prevent its release into the atmosphere.

Without unfair and punitive tax increases and unnecessary new regulations - we could create 1 million more new jobs in just seven years and increase revenue to the government by $127 billion by 2020. By 2030, this program of development could boost government revenue by $800 billion and increase daily production of oil and natural gas by 10 million barrels. Add to this more imports from Canada and increased domestic bio-fuel use and we could within 15 years have the capability to secure all of our liquid fuels from North American sources.

America’s oil and natural gas companies are owned by tens of millions of Americans. More than 29 percent of shares are held in mutual funds; 27 percent are held in pension funds; 23 percent are owned by individual investors; 14 percent are held in IRAs. Five percent are held by institutions and only 1.5 percent of industry shares are owned by corporate management. Raising taxes on America’s energy producers, businesses, and retirement plans is the wrong approach to rebuilding our economy. Therefore, these tax increases are nothing more than a billion dollar tax increase on America’s oil and natural gas industry, our employees, and our nation’s retirees.

View the original article here

The President’s Almost None-Of-The-Above Energy Approach

The president spoke about energy again Thursday, saying his all-sources strategy will ensure a prosperous future:

“If we’re going to avoid being at the mercy of these world events, we’ve got to have a sustained, all-of-the-above strategy that develops every available source of American energy.”

The president is right: A sustained strategy that uses all of America’s energy sources is the key to U.S. energy security. API President and CEO Jack Gerard:

“More oil and gas development here at home would benefit the nation. It would increase the security of our energy supplies, create jobs, boost revenue tour government and help put downward pressure on prices at the pump.”

Ah, but the president’s so-called all-of-the-above strategy actually appears to be an almost-none-of-the-above strategy. In a speech in Florida, he dismissed calls for increased domestic oil drilling:

“You know there are no quick fixes to this problem, and you know we can’t just drill our way to lower prices.”

And:

“Anybody who tells you we can drill our way out of this problem doesn’t know what they’re talking about — or just isn’t telling you the truth.”

This administration is talking a big game on energy – even claiming credit for domestic oil and natural gas production increases that stem from decisions made long before it came into office. Indeed, those gains have come in spite of the president’s policies, not because of them. And his rhetoric on drilling suggests ignorance or disdain for analysis that shows, yes, we could see 100 percent of our liquid fuel needs met with North American sources of oil by 2024.

Gerard:

“The administration is restricting where oil and natural gas development may occur, leasing less often, shortening lease terms, going slow on permit approvals and increasing or threatening to increase industry’s development costs through higher taxes, higher royalty fees, higher minimum lease bids and more regulations.”

More Gerard:

“Keeping 85 percent of our offshore areas off limits – per the administration’s latest offshore energy plan – is not a prescription for increased oil and natural gas production. Decreasing oil and gas leasing in the Rockies by 70 percent is not generating jobs and more affordable energy that America’s workers and consumers need. Having 10 federal agencies planning more regulation of hydraulic fracturing … is not keeping affordable supplies of gas flowing to generate electricity, heat homes and supply chemical plants. Rejecting the Keystone XL pipeline is not increasing American access to affordable, secure energy.”

Current energy conditions, globally and domestically, are pulling the veil away from the president’s do-little energy policies. You can’t reject the Keystone XL pipeline, for example, then say the United States is at the mercy of the volatility in global energy markets. You can’t keep U.S. energy on federal lands and offshore off limits and say you’re for increased domestic oil and natural gas production. You can’t say yours is an all-of-the-above strategy when you’re denying multiple opportunities to industries that supply the majority of the energy we currently use.

Gerard:

“The administration’s own projections tell us that we’re still going to rely on oil and natural gas for nearly 60 percent of our energy for the next quarter century. We’re either going to produce that oil and gas in the U.S. with the added benefits of creating over a million new American jobs, strengthening our national security and generating more revenue for our government, or we’re going to depend more on resources from less stable parts of the world.”

View the original article here

Raising Energy Taxes – The Wrong Approach

Update: The U.S. Senate failed to reach the 60 votes needed to invoke cloture and the motion failed 51-47. (29 Mar 2012)

Today the Senate will vote to advance S.2204 sponsored by Sen. Menendez (D-NJ). This bill will raise taxes on major integrated oil and natural gas companies to subsidize other forms of energy and will do absolutely nothing to lower gasoline prices.

A new poll conducted by Harris Interactive, from March 9-13 of registered voters nationwide, found that 76% of voters believe that increasing energy taxes could increase consumer costs on a wide variety of products, including higher gasoline prices.

American voters overwhelming oppose higher taxes!

Additionally, this bill claims to end alleged “subsidies” for a handful of oil and natural gas companies. However, nothing could be further from the truth. The U.S. oil and natural gas industry does not receive “subsidized” payments from the government to produce oil and gas. In fact, the Wall Street Journal editorial board states “the truth is that this industry is subsidizing the government.” The US oil and natural gas industry on average pays over $86 million every day to the federal government in taxes, rents, royalties and lease payments.

U.S. oil and natural gas companies pay considerably more of its profits in taxes than the average manufacturing company. In fact, in 2010, the industry paid more in total taxes than any other industry sector while averaging a 41% effective tax rate. Also in 2010, oil and natural gas companies directly contributed over $470 billion to the U.S. economy in spending, wages, and dividends – more than half the size of the 2009 federal stimulus package ($787 billion) – only this stimulus didn’t require an act of Congress.

Below are more details on the specific negative effects of the tax provisions that are included in the Menendez bill:

Dual Capacity/Foreign Tax Credit denial: API’s one pager discussing how this will make American companies uncompetitive abroad is here and there are more in-depth studies on this topic here, here and here. Despite rhetoric, the provision they seek to modify ironically is a more stringent rule on taxpayers like the oil and gas industry that has, for the last 3 decades, ensured abuses do not occur. The foreign tax credit can only be used to offset foreign income taxes paid and not any other payment. Without this foreign tax credit, which has been in place since 1918, US-based companies would be substantially disadvantaged when trying to develop foreign opportunities. Specifically, companies would face the cost of double taxation on foreign operations, while their competitors would only be taxed once.Sec. 199 repeal: Section 199 is available to every single domestic manufacturer and extractive industry that qualifies and is in no way unique to the oil and gas industry. As seen here, the oil and gas industry is already penalized with respect to others as we receive a 6% deduction on income from qualified activities; everyone else receives a 9% deduction. This provision was put into place in the American Jobs Creation Act in 2004 to create and keep jobs in the U.S. – exactly what we are doing. We support 9.2 million jobs in the U.S. and contribute to 7.7% of GDP. By removing this provision from just a handful of companies it sends the message a job in the oil and gas industry is not as “valuable” as a job at Starbucks or the New York Times (both of whom get 199 at 9%). Studies have shown repealing Sec. 199 (and IDC below) for the entire industry could put 165,000 direct/indirect jobs at risk by 2020.Repeal of drilling cost deduction (IDCs): Just like the R&D deduction (comparison here) our companies can deduct costs associated with the labor and construction of a well. As you can see in this one-pager, these costs, typically 60-80% of the cost of a well, are simply cost recovery with respect to timing – there is no credit or government subsidy here. Cost recovery allows us to put that money back into projects, technology and high wages. The average upstream wage is approx $98,000/yr. This provision is not unique to the Code and could compromise thousands of jobs and billions of dollars worth of capital – in fact, this repeal along with (Sec. 199 above) could compromise 10% of America’s oil and gas production capacity by 2017.Percentage depletion: The major integrated US oil and gas companies (the target of this amendment) are not eligible for percentage depletion and have not been for over 30 years. IPAA has more on how this affects independent producers.Repeal of tertiary injectant deduction: The U.S. is a mature oil producing region but still contains many viable fields whose lives are extended through the use of tertiary injectants. These efforts secure additional U.S. production and enable many production companies to remain in business. Changing how these costs are recovered could force producers to shut in older fields and significantly impact local economies. This deduction supports using carbon dioxide in enhanced oil recovery projects, one of the primary methods by which carbon dioxide is currently stored to prevent its release into the atmosphere.

Without unfair and punitive tax increases and unnecessary new regulations - we could create 1 million more new jobs in just seven years and increase revenue to the government by $127 billion by 2020. By 2030, this program of development could boost government revenue by $800 billion and increase daily production of oil and natural gas by 10 million barrels. Add to this more imports from Canada and increased domestic bio-fuel use and we could within 15 years have the capability to secure all of our liquid fuels from North American sources.

America’s oil and natural gas companies are owned by tens of millions of Americans. More than 29 percent of shares are held in mutual funds; 27 percent are held in pension funds; 23 percent are owned by individual investors; 14 percent are held in IRAs. Five percent are held by institutions and only 1.5 percent of industry shares are owned by corporate management. Raising taxes on America’s energy producers, businesses, and retirement plans is the wrong approach to rebuilding our economy. Therefore, these tax increases are nothing more than a billion dollar tax increase on America’s oil and natural gas industry, our employees, and our nation’s retirees.

View the original article here

The President’s Almost None-Of-The-Above Energy Approach

The president spoke about energy again Thursday, saying his all-sources strategy will ensure a prosperous future:

“If we’re going to avoid being at the mercy of these world events, we’ve got to have a sustained, all-of-the-above strategy that develops every available source of American energy.”

The president is right: A sustained strategy that uses all of America’s energy sources is the key to U.S. energy security. API President and CEO Jack Gerard:

“More oil and gas development here at home would benefit the nation. It would increase the security of our energy supplies, create jobs, boost revenue tour government and help put downward pressure on prices at the pump.”

Ah, but the president’s so-called all-of-the-above strategy actually appears to be an almost-none-of-the-above strategy. In a speech in Florida, he dismissed calls for increased domestic oil drilling:

“You know there are no quick fixes to this problem, and you know we can’t just drill our way to lower prices.”

And:

“Anybody who tells you we can drill our way out of this problem doesn’t know what they’re talking about — or just isn’t telling you the truth.”

This administration is talking a big game on energy – even claiming credit for domestic oil and natural gas production increases that stem from decisions made long before it came into office. Indeed, those gains have come in spite of the president’s policies, not because of them. And his rhetoric on drilling suggests ignorance or disdain for analysis that shows, yes, we could see 100 percent of our liquid fuel needs met with North American sources of oil by 2024.

Gerard:

“The administration is restricting where oil and natural gas development may occur, leasing less often, shortening lease terms, going slow on permit approvals and increasing or threatening to increase industry’s development costs through higher taxes, higher royalty fees, higher minimum lease bids and more regulations.”

More Gerard:

“Keeping 85 percent of our offshore areas off limits – per the administration’s latest offshore energy plan – is not a prescription for increased oil and natural gas production. Decreasing oil and gas leasing in the Rockies by 70 percent is not generating jobs and more affordable energy that America’s workers and consumers need. Having 10 federal agencies planning more regulation of hydraulic fracturing … is not keeping affordable supplies of gas flowing to generate electricity, heat homes and supply chemical plants. Rejecting the Keystone XL pipeline is not increasing American access to affordable, secure energy.”

Current energy conditions, globally and domestically, are pulling the veil away from the president’s do-little energy policies. You can’t reject the Keystone XL pipeline, for example, then say the United States is at the mercy of the volatility in global energy markets. You can’t keep U.S. energy on federal lands and offshore off limits and say you’re for increased domestic oil and natural gas production. You can’t say yours is an all-of-the-above strategy when you’re denying multiple opportunities to industries that supply the majority of the energy we currently use.

Gerard:

“The administration’s own projections tell us that we’re still going to rely on oil and natural gas for nearly 60 percent of our energy for the next quarter century. We’re either going to produce that oil and gas in the U.S. with the added benefits of creating over a million new American jobs, strengthening our national security and generating more revenue for our government, or we’re going to depend more on resources from less stable parts of the world.”

View the original article here

The President’s Almost None-Of-The-Above Energy Approach

The president spoke about energy again Thursday, saying his all-sources strategy will ensure a prosperous future:

“If we’re going to avoid being at the mercy of these world events, we’ve got to have a sustained, all-of-the-above strategy that develops every available source of American energy.”

The president is right: A sustained strategy that uses all of America’s energy sources is the key to U.S. energy security. API President and CEO Jack Gerard:

“More oil and gas development here at home would benefit the nation. It would increase the security of our energy supplies, create jobs, boost revenue tour government and help put downward pressure on prices at the pump.”

Ah, but the president’s so-called all-of-the-above strategy actually appears to be an almost-none-of-the-above strategy. In a speech in Florida, he dismissed calls for increased domestic oil drilling:

“You know there are no quick fixes to this problem, and you know we can’t just drill our way to lower prices.”

And:

“Anybody who tells you we can drill our way out of this problem doesn’t know what they’re talking about — or just isn’t telling you the truth.”

This administration is talking a big game on energy – even claiming credit for domestic oil and natural gas production increases that stem from decisions made long before it came into office. Indeed, those gains have come in spite of the president’s policies, not because of them. And his rhetoric on drilling suggests ignorance or disdain for analysis that shows, yes, we could see 100 percent of our liquid fuel needs met with North American sources of oil by 2024.

Gerard:

“The administration is restricting where oil and natural gas development may occur, leasing less often, shortening lease terms, going slow on permit approvals and increasing or threatening to increase industry’s development costs through higher taxes, higher royalty fees, higher minimum lease bids and more regulations.”

More Gerard:

“Keeping 85 percent of our offshore areas off limits – per the administration’s latest offshore energy plan – is not a prescription for increased oil and natural gas production. Decreasing oil and gas leasing in the Rockies by 70 percent is not generating jobs and more affordable energy that America’s workers and consumers need. Having 10 federal agencies planning more regulation of hydraulic fracturing … is not keeping affordable supplies of gas flowing to generate electricity, heat homes and supply chemical plants. Rejecting the Keystone XL pipeline is not increasing American access to affordable, secure energy.”

Current energy conditions, globally and domestically, are pulling the veil away from the president’s do-little energy policies. You can’t reject the Keystone XL pipeline, for example, then say the United States is at the mercy of the volatility in global energy markets. You can’t keep U.S. energy on federal lands and offshore off limits and say you’re for increased domestic oil and natural gas production. You can’t say yours is an all-of-the-above strategy when you’re denying multiple opportunities to industries that supply the majority of the energy we currently use.

Gerard:

“The administration’s own projections tell us that we’re still going to rely on oil and natural gas for nearly 60 percent of our energy for the next quarter century. We’re either going to produce that oil and gas in the U.S. with the added benefits of creating over a million new American jobs, strengthening our national security and generating more revenue for our government, or we’re going to depend more on resources from less stable parts of the world.”

View the original article here