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The infamous BP oil spill caused chaos in the US deepwater oil industry, but now drilling in the US Gulf of Mexico (GoM) is making a comeback, according to natural resources experts GlobalData.

New research released by GlobalData, a leading business intelligence provider for the energy sector, states that despite the increased US government restrictions that followed the Deepwater Horizon explosion – combined with the risks and high costs involved in deepwater drilling – climbing crude oil prices will see GoM oil production surpass its former records.

Matthew Jurecky, Global Director of Energy Research and Consulting for GlobalData, recently stated in a prior release that, “The rise in crude oil prices, and consequently retail gasoline prices, was and is inevitable. The global economy is at one of its lowest points in decades and crude oil prices are still set to average a record high for 2012.”

Now, GlobalData’s report, Deep Offshore Oil & Gas Exploration and Production (E&P) in West Africa – Market Analysis, Competitive Landscape and Forecasts to 2020, states that the increasing price of crude oil means that offshore Brazil, offshore West Africa and the US Gulf of Mexico are forming a “Golden Triangle” for deepwater oil exploration and production.

BP plc’s Macondo well experienced a blowout in April 2010, resulting in the destruction of the Deepwater Horizon drilling rig, a 5 million barrel (MMbbl) oil spill, and a six-month moratorium issued by the US government for certain areas of the GoM. However, a recent surge in issued permits indicates the return of large-scale deepwater drilling to the area.

The US government issued 44 deepwater drilling permits (including permits issued for new wells, bypass and sidetrack, excluding revised permits). This is a promising figure considering that throughout all of 2011 and 2010 the US government issued only 79 and 74 permits respectively. This growth suggests that deepwater drilling in the GoM will return to levels seen before April 2010 by the end of 2012.

One major attraction for deepwater oil exploration in the GoM is the stable political climate and clear regulations, while many other parts of the world see oil and gas investment opportunities marred by regime changes or nationalization. The US and Mexican governments entered into an agreement in February 2012, that set a framework to facilitate hydrocarbon exploration and production in the GoM. The agreement enables lease operators in the US GoM to coordinate with Petroleos Mexicanos (Pemex), the Mexican National Oil Company (NOC) for the joint exploration and production of hydrocarbons in the GoM in the Mexican maritime boundary of GoM. The agreement allows a greater level of freedom for US oil corporations, and is expected to increase investment and drilling in the GoM.

Major International Oil Companies (IOCs) such as BP and Chevron Corporation have always dominated deepwater drilling in the GoM, and are at the forefront of the drilling resurgence. Out of the 44 deepwater drilling permits issued in Q1 2012, BP (with 13) and Chevron (with 14) garnered the majority. IOCs hold the required technological expertise and the capacity to fund high capital expenditure and potential multi-billion-dollar liability risks in the event of another oil spill.

However, the dominance of IOCs in the GoM deepwater exploration is enhanced by an apparent lack of interest from some small independent US operators, as regions such as the Bakken and Eagle Ford shales offer attractive opportunities without the levels of risk involved in deepwater drilling.

original article

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The infamous BP oil spill caused chaos in the US deepwater oil industry, but now drilling in the US Gulf of Mexico (GoM) is making a comeback, according to natural resources experts GlobalData.

The states that despite increased US government restrictions which followed the Deepwater Horizon explosion – combined with the risks and high costs involved in deepwater drilling – climbing crude oil prices will see GoM oil production surpass its former records.

BP plc’s Macondo well experienced a blowout in April 2010, resulting in the destruction of the Deepwater Horizon drilling rig, a 5 million barrel (MMbbl) oil spill, and a six-month moratorium issued by the US government for certain areas of the GoM. However, a recent surge in issued permits indicates the return of large-scale deepwater drilling to the area.

The US government issued 44 drilling permits in Q1 (January to March) of 2012 -a promising figure considering that throughout all of 2011 and 2010 the US government issued only 79 and 74 permits respectively. This growth suggests that deepwater drilling in the GoM will return to levels seen before April 2010 by the end of 2012.

One major attraction for deepwater oil exploration in the GoM is the stable political climate and clear regulations, while many other parts of the world see oil and gas investment opportunities marred by regime changes or nationalization. The US and Mexican governments entered into an agreement in February 2012, which set a framework to facilitate hydrocarbon exploration and production in the GoM. The agreement enables lease operators in the US GoM to coordinate with Petroleos Mexicanos (Pemex), the Mexican National Oil Company (NOC) for joint exploration and production of hydrocarbons in the GoM in the Mexican maritime boundary of GoM. The agreement allows a greater level of freedom for US oil corporations, and is expected to increase investment and drilling in the GoM.

Major International Oil Companies (IOCs) such as BP and Chevron Corporation have always dominated the deepwater drilling in the GoM, and are at the forefront of the drilling resurgence. Out of the 44 deepwater drilling permits issued in Q1 2012, BP (with 13) and Chevron (with 14) garnered the majority. IOCs hold the required technological expertise, and the capacity to fund high capital expenditure and potential multi-billion-dollar liability risks in the event of another oil spill.

However, the dominance of IOCs in the GoM deepwater exploration is enhanced by an apparent lack of interest from some small independent US operators, as regions such as the Bakken and Eagle Ford shales offer attractive opportunities without the levels of risk involved in deepwater drilling.

original article

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The Bureau of Safety and Environmental Enforcement (BSEE) initiated the first ever drill designed to deploy critical pieces of state-of-the-art well control equipment to the ultra-deep seabed of the Gulf of Mexico in an effort to exercise the oil and gas industry’s response to a potential subsea blowout. The multi-week exercise, launched at 8:10 am CDT and employing the Marine Well Containment Company (MWCC), is part of a series of planned and unannounced exercises and inspections conducted by BSEE to ensure the industry’s ability to meet the conditions of their oil spill response plans and effectively respond to a potential spill.

Following the Deepwater Horizon incident, the Interior Department undertook the most aggressive overhaul of oil and gas safety regulations in U.S. history. Included in these reforms is the expectation that companies would have access to and could deploy surface and subsea containment resources that would be adequate to promptly respond to a blowout or other loss of well control, several components of which are being tested in this exercise initiated today.

In May, Secretary of the Interior Ken Salazar directed MWCC to conduct a live drill as an opportunity to deploy systems, test readiness for a worst-case scenario, and train under real-time conditions.

“This exercise will help further enhance industry’s preparedness by deploying one important component of their well control capabilities to the sea floor,” said BSEE Director Jim Watson. “Testing this equipment in real-time conditions and ultra-deep water depths will help ensure that the MWCC is ready and able to respond in a moment’s notice should the need arise.”

The demonstration is part of President Obama’s goal of expanded responsible production of our domestic energy resources while ensuring the strongest possible safety and environmental oversight of offshore oil and gas activities on the U.S. Outer Continental Shelf.

The exercise will involve the mobilization and field deployment of the capping stack to the sea floor in approximately 7,000 feet of water, latching it to a test wellhead, and pressurizing the system. The exercise is also designed to test an operator’s ability to obtain and schedule the deployment of the supporting systems necessary for successful containment – including debris removal equipment and other oil collection devices. The MWCC capping stack is similar to the one that was used to stop the flow of oil from the Deepwater Horizon well.

BSEE inspectors, engineers, and spill response experts will be embedded in various locations throughout the exercise, including in the command center and on the vessel deploying the capping stack, to oversee the mobilization, deployment, and associated tests of the system. BSEE experts will oversee the capping stack being lowered to the seafloor by wire, a technique that offers the potential to be significantly faster than the deployment via pipe that occurred during the Deepwater Horizon response.

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BP has started production at a key new oil operation under more than a mile of water in the Gulf of Mexico, where it expects production to peak at 60,000 barrels a day of oil equivalent, the company says.

Production started up on June 3 at the Galapagos development, which now includes three wells that BP owns jointly with Noble Energy, Red Willow and Houston Energy, BP said.

It is located about 140 miles southeast of New Orleans, far from its namesake Galapagos Islands in the Pacific Ocean, and is under about 6,500 feet of water.

The project began development in 2006. One of its wells, the Santiago, was the first to receive a permit after the federal government lifted a deep-water drilling moratorium it imposed following the deadly 2010 oil spill at the BP-owned Macondo well.

”The start-up of this project in the Gulf of Mexico is one of BP’s key operational milestones for 2012,” CEO Bob Dudley said in a statement.

Despite the 2010 spill, for which the company is still engaged in restoration efforts and settlement negotiations, BP has continued to bank on major hydrocarbon developments in the Gulf.

The company said it is the largest leaseholder in the Gulf, with more than 650 leases, and has interests in more than 20 fields there.

James Dupree, regional president of BP’s U.S. Gulf of Mexico business, said in a statement that Galapagos ”reflects the potential we continue to see in this world-class basin, now and in the future.”

The Galapagos development includes the Isabela, Santiago and Santa Cruz fields.

Noble Energy discovered the Santiago prospect last year. It is operating the Santiago and Santa Cruz fields, while BP is operating the Isabela field, BP said.

BP has a 56 percent stake in the project. It is the first new Gulf development to come online for BP since the spill, although the company has drilled and begun production at a new well this year in the existing Thunder Horse development.

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Local businesses say the recovery of deepwater offshore drilling has created an upswing in local shipbuilding and offshore service businesses.

But while business is recovering from the moratorium, there are still problems with new oil and gas industry regulations enacted after the Deepwater Horizon spill. The continuing regulatory issues have led to decreased federal revenue, fewer active rigs in the Gulf and lower forecasts of future production from the Gulf of Mexico, according to a report released last week by the Thibodaux-based Gulf Economic Survival Team.

Loren Scott, professor emeritus at LSU’s E.J. Ourso College of Business, laid out his forecast for the oil and gas industry in the state at a meeting of the South Central Industrial Association meeting in Houma last month.

Scott predicted the Gulf’s deepwater petroleum production should be completely recovered by the middle of next year.

Scott noted that 169 drill permits were approved in 2009, with 33 deep water rigs operational. Through the first quarter of this year, 44 permits had been approved. There are 24 rigs online with nine drill ship and semi-submersibles coming soon.

All that is good news for local offshore service businesses and shipbuilding companies, he said.

Robert Socha, a spokesman for Bollinger Shipyards, said the company has up to 10 years of work lined up for projects at one of its shipyards, and the company is hiring qualified workers.

The shipyard works in new construction, and has projects to build U.S. Coast Guard boats, tugboats and supply boats for the oil and gas industry. It also works in repair and conversion of vessels, which will “have the most opportunities” with business picking up, he said.

He said projects related to new deepwater drilling projects have already affected the market, and there’s a shortage of certain types of boats that are in demand for deepwater drilling.

“The industry is going to gain from that,” he said.

Chett Chaisson, director of Port Fourchon, said the port is experiencing an uptick in business because of recovering deepwater drilling business. It is nearing the level of business it saw before the ban on deepwater drilling, he said.

There’s been an increased interest in port property to service and support deepwater activity, and companies looking to develop new facilities and significantly invest in the port.

A lot of that activity is because of the culmination of a year and half worth of drilling permits beginning to be issued and work getting under way, Chaisson said.

But the process to issue drilling permits is still slow and onerous, he said.

Lori LeBlanc, executive director of the Gulf Economic Survival Team, which was formed after the offshore drilling ban to lobby for local industry, said that the industry outlook is optimistic compared to where it’s been at since the oil spill and drilling moratorium, but there are still problems.

The group’s new report was conducted by Southern Methodist University researchers examining the fallout of new regulations on the oil and gas industry.

“It’s important to break down these numbers” relating to rig counts and permits, LeBlanc said.

For example, prior to the deep­‐water moratorium, there was an average of 27 “active” rigs in the Gulf, rigs currently engaged in drilling-related activities as opposed to maintenance or other activities. But May 1, there were only 18 active rigs in the Gulf.

Offshore lease sale revenue has also dwindled. In 2008, $9.4 billion was generated in new offshore lease bids. That dropped to $979 million in 2010, and $36 million in 2011, with only one lease sale held the entire year.

In addition, the average number of days to have a drilling plan approved by federal officials has risen from 50 days to 207 days. And while the administration approved 94 permits for wells in March, only 32 of those covered new wells permitted to reach oil and gas.

In addition, many companies aren’t getting the permits they need to keep working and move from job to job.

“The industry needs predictability and stability,” LeBlanc said. “Things are happening, … but it isn’t where it should be or it needs to be.”

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While deepwater drilling presents a myriad of challenges, perhaps one of the most economically and technically taxing relates to the risk of lost circulation. This phenomenon, in which whole drilling mud enters the formation from the wellbore, introduces several setbacks, ranging from the loss of thousands of barrels of expensive drilling mud to the irreversible collapse of the wellbore.

There are a number of technical solutions to prevent this, and liner drilling technology is one of the most viable candidates. Drilling-with-liner alleviates several wellbore instability concerns, including minimizing lost circulation. The technique also introduces a narrow annular geometry, which reduces the rate of fluid loss in the annulus and enables effective management of the annular fluid level, as contrasted to conventional drilling operations. Liner drilling has been shown to minimize or eliminate nonproductive time in operations in which uncontrolled fluid losses have been encountered previously.

Weatherford has developed a suite of liner drilling technologies designed to mitigate instability issues and address the challenges of drilling through narrow mud weight/pore pressure/fracture gradient windows that conventional methods cannot.

Deepwater case history

A deepwater Gulf of Mexico operator availed of liner drilling technologies to develop updip reserves in a deep, depleted gas reservoir located in 2,900 ft of water.

The planned well was a replacement for a well that had produced from a deep sand interval below 18,000 ft true vertical depth (TVD). This sand interval was drawn down 5,000 psi to an estimated 8.0 ppge (equivalent) pore pressure, while virgin shales and wet sands above the pay had pore pressures of 13.7 to 14.4 ppge compared with the 10.5-11.5 ppge fracture gradient that was anticipated in the target sand.

A shallower pay interval at 15,000 ft TVD dictated the need for a high casing seat and an S-shaped wellbore with a 5,000 ft long section at a 60° inclination and a departure from vertical of some 5,000 ft in order to access the deeper depleted sand at the planned location.

The main challenge for the operator was to drill and set casing through a normally pressured shale and a depleted sand within one hole section towards its end (Fig. 1). Achieving this with conventional methods would most likely require two strings of casing, with increased risk of failing to reach the target depth.

The well plan would not allow for an additional string to be utilized due to severe slimming of the wellbore. The operator created a multidiscipline operations team to prepare procedures for drilling in a 75⁄8-in. liner through unstable shale formation, while also mitigating any potential hole instability and depletion issues. A review of drilling reports from the original producing well showed that two sidetracks were required to successfully install the 75⁄8-in. production liner completion assembly as hole instability was an ongoing problem.

Subsequent wellbore analysis led to the conclusion that the depleted commercial sand section would be unstable at hole inclinations exceeding 22°. Higher inclinations would make wellbore stability a challenge, and would require incrementally higher mud weights and increase the probability of severe lost circulation.

Rock mechanics analysis predicted that the wellbore through the sand zone would be unstable at deviations greater than 50° and that the mud weight would have to be sufficient to keep the wellbore open by offsetting the weight of the overburden acting to close the well. Mud weight has to increase with increasing deviation, but if the mud weight exceeds the fracture gradient, lost circulation would occur.

Conversely, a mud weight that is too low would cause wellbore collapse. This same wellbore analysis also concluded that shale failure would occur at mud weights less than 12.5 ppg and that a main objective should be to reduce the amount of shale exposed by keeping the hole close to vertical in that section. The mud weight required would vary from 13 ppg at 22° to 13.7 ppg at 60°.

To avoid mud losses the nominal mud weight while drilling the target sand would need to be 10.3 ppg with very little drilling window margin of error being available. The wellbore analysis indicated that a mud weight of 9.6 ppg may be preferable to provide headroom for the equivalent circulating density (ECD) that would exist while drilling.

The drilling plan

After a full review, the operations team decided that a 75⁄8-in. liner would be drilled into the pressured shale formation and set and cemented just above the depleted sand target zone. To minimize the shale section exposed, which would theoretically close in with 10 ppg mud, a 51⁄2-in. liner would be drilled into the target sand itself and cemented in place.

Several features of liner drilling were considered beneficial to this operation. First, liner drilling had a successful track record of minimizing or even eliminating lost circulation problems due to the so-called “smear effect.” This effect is believed to occur due to the close proximity of the casing to the wellbore, resulting in cuttings being smeared against the formation to create an impermeable mud cake. In regular drilling operations the greater space between the drill pipe and the wellbore does not promote this.

This same reduction in annular space also leads to much higher annular velocities for the same flow rate, leading to better hole cleaning—an important benefit in unstable shale formations. Once liner setting depth is reached, cementation can occur almost immediately, further reducing the need for hole cleaning that is typically associated with standard drilling operations before casing is set. This can result in significant rig time savings and remove the risks associated with tripping the drill pipe.

Because the liner drilling operation was to be carried out in a water depth of 2,900 ft, additional factors had to be included in the drilling plan. Operational procedures were written to highlight the differences between liner drilling and conventional drilling operations in deep water, and training sessions were held for key drilling personnel, service engineers, and third parties to ensure that these differences were fully understood.

The liner was fitted with rigid body, spiral blade centralizers to reduce the potential for differential sticking.

In addition, contingency plans were prepared in the event of fluid losses during liner drilling, as the preset shear pin pressures for the hydraulic liner system hanger and running tools were sensitive to differential pressures between the inside of the liner sting string and the annulus.

With partial fluid losses, if the annulus could be kept full, drilling ahead could continue. If the annular fluid level could not be managed, the liner would be cemented in place immediately. In the event of fluid losses both inside the liner and in the annulus, the liner would be set and cemented immediately so that the well could be secured.

Equipment selection

To select suitable equipment for the proposed project, consideration had to be given to torque and drag probabilities, liner connection torsional strength, cyclic fatigue resistance, drilling fluid hydraulics, and surge concerns while running the liner in the well.

The following equipment was selected for the 75⁄8-in. drilling liner:

• A 75⁄8-in., 39 ppf, Q-125, HYD 523 liner was chosen following mechanical and fatigue analysis of estimated liner drilling loads based on 20,000 lb weight on bit (WOB), 100 RPM for 150 hr, and 60° hole inclination.

• A three-bladed, 75⁄8 in. by 81⁄2 in. casing-while-drilling (CwD) bit incorporating PDC cutters on the shoulder was chosen for the application (Fig. 2). This bit contains an aluminum nose housing the three blades and three interchangeable 18⁄32-in. copper nozzles for hydraulics optimization. The CwD bit is drillable with conventional PDC bits as well as tricone bits, eliminating a dedicated bit and trip for drill out.

• Two double poppet valve high-temperature/high-pressure (HTHP) 75⁄8-in. float collars were placed 44 ft and 93 ft, respectively, above the CwD bit. The float collars provided a mechanical barrier for well control, as in a drill pipe float valve, and a one-way check system to prevent the cement to U-tube after the primary cement job.

• Two 75⁄8 in. by 81⁄4 in. blade OD centralizer subs were placed 22 ft and 46 ft, respectively, above the CwD bit.

• A 75⁄8 in. by 97⁄8 in. premium liner hanger system with a mechanically set liner top packer and a hydraulically locked, mechanically released liner setting tool, all capable of withstanding the calculated extremes of force that were used in the verification of the choice of liner connection.

Similar equipment was chosen for the 51⁄2-in. production liner but sized appropriately for the smaller liner.

Drilling the well

After setting casing strings and setting the 117⁄8-in. liner at 11,100 ft measured depth (MD), the liner shoe was drilled out and the hole kicked off, building angle at the rate of 3.5°/100 ft until an inclination of 59° was reached at a depth of 15,000 ft MD. The remaining 105⁄8 in. by 121⁄4 in. hole was drilled to 16,550 ft MD while maintaining this hole inclination.

Logging and evaluation were then performed, followed by setting 97⁄8-in. intermediate casing at 16,300 ft MD. An 81⁄2-in. hole section was drilled with synthetic oil base mud (SBM) to 20,455 ft MD when the rotary steerable system’s bottomhole assembly (BHA) failed. Subsequently, the BHA failed twice and the hole packed off, resulting in the loss of the hole and the well having to be plugged back.

Bypass No. 1 was then drilled to a depth of 20,356 ft MD (18,053 ft TVD) using the 14.5 ppg synthetic base mud weight required for hole stability through the pressured shale formation, while maintaining a 50° inclination. The inclination was dropped to 20° to facilitate drilling of the depleted sand at the recommended angle. The target sand was encountered some 37 ft higher than expected and total fluid loss resulted while drilling with the 14.5 ppg SBM.

As a result, the annulus quickly packed off with the annulus fluid level remaining full, resulting in loss of the BHA. The drillstring was recovered and a second 81⁄2 in. by 97⁄8 in. bypass hole was drilled to 20,419 ft MD (18,040 ft TVD) and to a depth 13 ft TVD above the Bypass No. 1 TVD of 18,053 ft. The inclination at that depth was reduced to 20° to facilitate eventual drilling into the target depleted sand at the recommended angle.

The drillstring was then pulled after circulating to condition the well and 4,536 ft of 75⁄8 in. by 97⁄8 in. liner—complete with the CwD bit, liner hanger, packer, and setting tool—was tripped in the well at 9.7 fpm (9.4 min/stand) on the 51⁄2-in., 24.7 ppf, S-135, XT-57 drill pipe running string to a depth of 20,320 ft MD. The slow trip speed was required to minimize fluid losses to the exposed formations.

The 75⁄8-in. liner was then washed and reamed a total of 99 ft to TD and drilled a further 8 ft to 20,427 ft MD (18,049 ft TVD), some 15 ft above the top of the depleted commercial sand. Lost returns were encountered, with the annulus and liner running string remaining full.

The rotary stalled, and a decision was made to not work the pipe as the liner was at a sufficient depth to isolate the pressured shale and depleted interval. This enabled the mud weight in the subsequent hole section to be reduced to the 10 ppg required to drill the depleted commercial sand. The liner running string and annulus remained full. The 75⁄8-in. liner washing, reaming, and drilling process over the 107-ft interval took 31⁄2 hr to complete.

The liner hanger and packer were set and the liner cemented in place without incident. Following the prescribed period of waiting on cement, the float equipment, cement and CwD bit were drilled out with 12.7 ppg SBM and 5 ft of new 61⁄2-in. hole was drilled while reducing the mud weight to 10 ppg. The target zone was drilled using a 61⁄2 in. by 71⁄2 in. bicenter bit, maintaining the established inclination of 20° to 20,527 ft MD with full returns.

After conditioning the hole, the drill pipe and 61⁄2 in. by 71⁄2 in. BHA were retrieved and 328 ft of 51⁄2 in. by 75⁄8 in. production liner with 5½ in. by 61⁄2 in. CwD bit, liner hanger, packer, and running tool were run in. Weight on bit was required at 20,427 ft MD, from which point the liner was washed and reamed 100 ft to 20,527 ft MD (18,140 ft TVD).

The 51⁄2-in. liner washing and reaming process consumed 81⁄2 hr without fluid losses. The 51⁄2 in. by 75⁄8 in. liner was subsequently cemented in place without fluid losses, and the well was completed as planned.

Results and recommendations

The use of liner drilling technology greatly reduced the fluid losses in the annulus compared with conventional drilling methods deployed, most likely due to a combination of the “smear effect” and the reduced annular clearance that resulted.

Despite the difficulties encountered, which resulted in the loss of two hole sections due to the BHA failures, the target depth was reached successfully. Both liners were drilled and reamed in as planned. Given the hole conditions encountered, the operator concluded that the well could not have been completed without the use of liner drilling technology.

The operator and other service organizations involved in the project offered several recommendations on how to further improve liner drilling equipment and methodology.

To improve running and drilling hydraulics, the liner system needed to be redesigned to have more bypass area.

In addition, hydraulic liner hangers and setting tools need to have higher torque values to improve operations.

Rotation of pipe while making connections is advisable to facilitate the drilling of liners through thick depleted reservoirs and to lessen the probability of stuck pipe incidents.

Finally, a continuous circulating device is recommended when drilling through depleted intervals to allow for continuous pumping during the connection process.

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U.S. Rep. Steve Scalise, R-Metairie, is calling on state lawmakers to abandon a proposal that could allow the Legislature to redirect fines from the Deepwater Horizon disaster to projects unrelated to coastal restoration.

The measure, approved by the Senate Finance Committee Tuesday, was tacked onto House Bill 812, which would call for a referendum on a constitutional amendment directing all the fines the state receives as a result of the spill to the state’s Coastal Protection and Restoration Fund.

“The reason we have fought so strongly to dedicate the BP fines to the Gulf Coast states is to ensure that those monies are only spent on restoring the coast as well as the environmental and economic damage done by the Deepwater Horizon disaster,” Scalise said in a statement released Wednesday. “Just as we’ve made it clear to our colleagues in Congress that the BP fines should not be used for unrelated spending in Washington, the Legislature needs to make it clear that RESTORE Act funds will not be used for unrelated spending in Baton Rouge.”

Senators and representatives in Washington, D.C., are currently hammering out a final version of the RESTORE Act, which would provide a framework for distributing fines from the spill to the states impacted by the disaster.

The amendment adopted by state senators Tuesday would allow some of that money to go to other uses with the approval of two-thirds of each chamber of the state Legislature. Lawmakers would have to specify how the money was being used and would not be able to use it for purposes that were prohibited by Congress or any settlement agreement related to the money.

Supporters of the original bill argued that adding that language would weaken the state’s case for receiving the spill money.

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In an effort to tighten regulations for blowout preventers, the safety mechanism of last resort for offshore drilling, the top U.S. oil and gas regulator announced he is holding an all-day public forum in Washington, D.C., on May 22 to find ways to improve the reliability of the device that failed so miserably when the Deepwater Horizon rig exploded two years ago. James Watson, director of the Interior Department’s Bureau of Safety and Environmental Enforcement, spoke for the first time before the annual Offshore Technology Conference in Houston Tuesday.

He praised the industry for developing a raft of new technologies to make drilling safer after the Deepwater Horizon disaster.

He also said his revamped agency is sharpening its regulatory focus with four main efforts. First, he said BSEE is completing revisions to a drilling safety rule imposed on an emergency basis in October 2010 when the government decided to resume deepwater drilling for the first time since the April 2010 BP oil spill.

Second, he promised to finalize a workplace safety rule known as SEMS, one that hones regulations governing rig workers’ authority to stop work on a project if they see something dangerous, and similar provisions. It also requires independent third-party safety audits on working rigs.

Third, Watson notified the industry that while the drilling safety rule contained a number of provisions for blowout preventers, a separate rule governing their design, testing and maintenance is necessary because of the way the massive stack of valves and pistons failed to shut in the BP well, as it had been designed to do, two years ago. He said the May 22 forum in Washington will be key.

“We are inviting experts from around the country to participate in panel discussions, and I am looking forward to an open and candid dialogue,” he said.

Finally, Watson said revisions are long overdue for oil and gas production safety systems. That’s safety for the massive fixed platforms and spider-web networks of oil-producing wells, not the exploratory wells that are in the drilling stage. Watson said those production safety systems haven’t gone through a significant update since 1988, and he said issues his agency found on BP’s Atlantis platform produced some of the proposed revisions.

A former BP contract worker on Atlantis sued BP in federal court in Houston claiming the company hadn’t maintained proper documents on board the platform and hadn’t gotten certified engineers to approve certain systems. BP denies any substantive violations occurred with the maintenance of records and said it got proper approvals from regulators when it used foreign engineers who weren’t U.S. certified.

Atlantis seems to exemplify the need for tighter controls on production platforms, even if no evidence has emerged of any major violations there. Emails in the court record detail several incidents in which BP workers were baffled by self-activating valves, power failures and potential subsea leaks, none of which were reported to regulators. But BP said these were not significant enough incidents to require any reporting to the government. Testimony from Bryan Domangue of the government’s Houma district office did not clearly show whether the regulators should have been aware of those issues or not.

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