Wood Mackenzie Reviews Recovery of Production in Libya

- Wood Mackenzie Reviews Recovery of Production in Libya

Friday, August 26, 2011
Wood Mackenzie

Following recent events in Libya, Wood Mackenzie has reviewed its analysis of how long it could take for a recovery of oil and gas production. One of the key issues in this respect is how quickly the National Transitional Council (NTC) can stabilise the security situation across the country.

• It is too early to expect a material recovery in Libya's oil and gas production. "Once a resolution is reached, we believe it will take around 36 months for oil production to recover to the pre-conflict level of 1.6 million barrels a day (b/d). It may be possible, however, for up to 600,000 b/d to be restored within three months assuming a swift end to hostilities, and an early focus by the NTC and international community on stability and infrastructure repair," said Ross Cassidy, North Africa Upstream Research Analyst for Wood Mackenzie.
• Wood Mackenzie's global gas research shows that gas production could take less time to recover. Eight billion cubic meters of gas per year is contracted from Libya to Italy, with Eni as primary off-taker selling to customers in Italy. The Greenstream gas pipeline routes gas from Eni-operated fields in Libya to Italy.
• Massimo Di-Odoardo, European Gas & Power Research Analyst for Wood Mackenzie says, ”The Italian market is presently oversupplied with gas and Eni has had to delay off-take obligations from other suppliers because insufficient market is available. During the Greenstream outage, Eni increased off-take of Russian pipe gas supplies therefore, resumption of Greenstream will add gas to an already oversupplied Italian market with implications for downside price risk and reduced flows of pipe gas from other suppliers, notably Russia. It could take as little as three months to restart Greenstream supply and reach pre-crises production levels, however the time to resume supply will depend on local security and the state of infrastructure.”
• Wood Mackenzie estimates that it will take around 36 months for the country to recover its full production capacity, from whenever the current crisis reaches a resolution. This depends on the scale of damage to oil infrastructure being limited, swift removal of international sanctions and the timely return of international oil companies and foreign workers.
• The Libya state-owned National Oil Company (NOC) and the international industry will have to work in partnership to repair facilities, re-start production and ramp-up to pre-crisis rates. Production recovery is likely to vary by basin. It will take longer in the mature and complex Sirte basin, in eastern Libya, which is the foundation of Libyan production, than in the more modern and less complex fields of the Murzuk and Pelagian Shelf basins, of western Libya.
• Substantial oil volumes could be back in the market by late 2012, if a resolution is achieved by the end of 2011. But the recovery period will extend if production remains shut-in for longer, as infrastructure continues to deteriorate. There is unlikely to be any increase in production or re-start of exports, whilst Libya's oil infrastructure is open to sabotage by either side.
• In the longer-term, the production outlook will be largely dependent on the nature of the outcome to the conflict and its political fallout. Libya has the potential to produce up to 3 million b/d of oil and become a major gas exporter through partnering with the international industry, who will bring finance, skills and technology to existing fields. But, for now, this brighter future remains on hold until military operations are concluded.

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Gas Damage Recovery Fund Proposal Premature, Official Says

- Gas Damage Recovery Fund Proposal Premature, Official Says

Thursday, August 11, 2011
Rigzone Staff
by Karen Boman

A bill proposed by New York Comptroller Thomas P. DiNapoli to establish an energy industry-supported fund to cover damages caused by natural gas production seems premature since the Department of Environmental Conservation (DEC) has not completed work on the state's new permit requirements, said Brad Gill, executive director of the Independent Oil & Gas Association of New York.

"The proposal does not take into account existing permit requirements, which address bonding for site reclamation, and it does not acknowledge existing environmental, criminal and civil law, which holds businesses accountable on many levels," Gill said, noting that the state's new permit requirements would likely be the strictest in the nation.

"The industry's outstanding record of environmental protection in New York should give the public the assurance that we operate with the best interests of the environment in mind," said Gill. "There is simply no basis for such a fund at this time."

DiNapoli on Aug. 9 proposed Comptroller's Program Bill #20 to remediate contamination related to gas production; the proposed legislation would apply to current drilling operations as well as to proposed high-volume hydraulic fracturing.

"Preventing accidents and contamination should always be our first priority," said DiNapoli. "If an accident does occur, the State needs to be ready with a rapid response and a reliable mechanism to hold polluters responsible. New Yorkers should not have to bear the burden from contaminations that damage their air, water and property. Whatever final decisions are made regarding high-volume hydraulic fracturing, this program and new fund will provide the necessary resources to respond to any accidents."

DiNapoli's program is modeled after the New York State Environmental Protection and Spill Compensation Fund (Oil Spill Fund), which draws on the expertise and collaborative efforts of the DEC, the Office of the Attorney General and the Office of the State Comptroller.

Under the program, strict liability would be imposed on owners or operators of drilling sites that cause contamination. The DEC would be empowered to order immediate clean-up by owner or operator or take over sites for immediate clean-up, or would impose a surcharge on drilling permits to create the Natural Gas Damage Recovery Fund similar to structure to the existing Oil Spill Fund.

Oil and gas companies also would be required to post surety bonds to cover any shortfall between fund resources and remediation costs. Additionally, the program would create for the first time an online registry of all gas drilling related incidents in New York State.

The Natural Gas Damage Recovery Fund would pay for any remediation of contamination undertaken by DEC where a responsible party could not be identified, responsible parties refused or responsible parties were unable to pay for needed remediation, according to a statement from the comptroller's office.

The Office of the Attorney General would determine who is legally responsible for the contamination and, if necessary, commence civil damage-recovery litigation against responsible parties. Any recovered funds would be returned to the Natural Gas Damage Recovery Fund to cover cleanup of future contaminations.

DEC on July 1 released its revised recommendations on high-volume hydraulic fracturing, including the prohibition of high-volume fracturing in New York City and the Syracuse watersheds, including a buffer zone. DEC also is recommending the prohibition of drilling within primary aquifers and within 500 feet of their boundaries. Additionally, surface drilling also would be prohibited on state-owned land including parks, forest areas and wildlife management areas.

Previous recommendations had permitted drilling in the New York and Syracuse watersheds, as well as in primary aquifers and forest areas. DEC said the new recommendations would protect the state's environmentally sensitive areas while realizing the economic development and energy benefits of the state's gas resources, and that approximately 85 percent of the state's Marcellus shale resources would be accessible to gas extraction under these recommendations.

DEC plans to hold a 60-day public comment period on the recommendations beginning this month.

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Statoil, Partners Aim to Boost Recovery Rate at Njord License

- Statoil, Partners Aim to Boost Recovery Rate at Njord License

Wednesday, June 22, 2011
Statoil

Statoil and its partners in the Njord license in the Norwegian Sea have decided to invest in low-pressure field production. This, combined with other measures, will prolong the lifetime of the field until 2020.

Reservoir pressure on Njord is falling and the field has entered tail-end production. By lowering the pressure on the first and second stage separators it will be possible to increase production from individual wells and maintain production in each for an extended period.

"Owing to the complexity of the Njord reservoir the recovery rate of proven resources is currently roughly 23%. The aim is to increase the recovery rate to 30%. This type of measure is important with a view to maintaining production on the Norwegian continental shelf (NCS)," stated Ivar Aasheim, head of NCS field development.

There is currently a great deal of activity in the Njord area. The Njord northwest flank project six kilometers northwest of the Njord platform is now being carried out. It consists of two new long-distance wells drilled directly from Njord and tied back to the platform.

Several wells will be drilled in coming years. In addition, Hyme fast-track is being processed via Njord.

"In combination with the low-pressure production project these measures will prolong the lifetime of Njord until 2020," explained Njord production head Arve Rennemo.

The low-pressure production project on Njord will boost volumes by roughly 18.5 million barrels of oil equivalents alone and extend the field's working life by two to three years.

Investments in low-pressure production amount to roughly NOK 500 million.

The contracts for Njord low-pressure production modification and the Hyme topside has been awarded to Reinertsen. The contract for compressor procurement and installation was awarded in March of this year to GE Oil & Gas.

Project execution will take place in the autumn of 2012 and the start-up of low pressure production on Njord is scheduled for the fourth quarter of 2012.

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Mideast Oil Recovery Enters A New Phase

Mideast Oil Recovery Enters A New Phase

Thursday, April 28, 2011
Dow Jones Newswires
by Angus McDowall & Oliver Klaus

It has always been an axiom of world energy markets that Persian Gulf oil is both easy and cheap to produce.

The crude that gushes from the scorching desert sands of Saudi Arabia, for example, is widely thought to cost less than $5 a barrel to produce, compared to the $70 price tag on raising a barrel from deep Atlantic waters.

But many of the Persian Gulf oilfields have been producing for decades, and an increasing number of the newer fields in the region contain heavier and harder-to-extract crudes. Squeezing out the remaining reserves from some existing fields and developing new, more complicated ones will be costlier and will require more advanced technology, according to analysts and oilfield engineers.

As a result, more Gulf countries are exploring the use of enhanced oil recovery, or EOR, a collection of technologies that coaxes substantially more oil from the ground by injecting steam, gas and chemicals deep below the surface.

"The Middle East countries have varying levels of maturity in their fields," said Chris Graham, a Middle East analyst at Edinburgh-based oil consultancy Wood Mackenzie. While the major OPEC producers in the region mostly don't need to use EOR techniques, the situation is different for the smaller non-OPEC producers such as Oman and Bahrain. In those countries, "you've got maturing production profiles and each barrel becomes more difficult and more costly to extract," Graham said.

And even the large OPEC producers such as Kuwait have started to turn to EOR technology as they seek to develop new, more complex, heavy-crude reservoirs on which they will have to rely for future production growth. EOR tends to be needed most when oil is heavy--sometimes as thick as asphalt--and only flows when it is melted with steam, as is the case in some of Kuwait's yet-to-be-developed fields.

"EOR will become over the years an important component of what the industry collectively has to develop," said Jean-Luc Guizion, president of exploration and production at Total. "The luck of the Middle East countries is they have a lot of resources so they have ample time to plan the necessary EOR improvement."

According to technicians at one company with EOR operations, the methods can improve recovery rates in some fields by 40%, but at an additional cost of anywhere between $20 and $60 per barrel of oil.

In the so-called Partitioned Neutral Zone, shared between Saudi Arabia and Kuwait, Chevron is involved in an EOR scheme aimed at developing heavier crudes using steamflooding. Abu Dhabi Co. for Onshore Oil Exploration is working on an EOR project involving carbon dioxide injection. And Saudi Aramco is working on plans to implement a CO2 EOR demonstration plant in the next two years, although this project is, for now, aimed at trapping emissions rather than boosting recovery rates.

EOR techniques have been in use since the 1970s, when they mostly involved injecting seawater into reservoirs in order to maintain pressure and squeeze more oil from the porous, sponge-like rock where it is deposited. Now there's a far more diverse range of techniques on offer and experts say that each field requires its own mix of EOR techniques that can only be determined by complex analysis of field conditions and economics.

In the ancient and complex Marmul block in Oman, for instance, the oil is heavy and viscous. To improve the mix of oil and water in the field, the operating company, Petroleum Development Oman, which is 34% owned by Shell, injected polymer into the reservoir, allowing the crude to flow more freely and improving recovery by 10%.

Bahrain's energy minister Abdul Hussain bin Ali Mirza says his country's aging Bahrain field--where EOR boosted output from an average of 29,000 barrels a day to a level of 40,000 barrels a day within a year--will see output hit 100,000 barrels a day within seven years.

However, while Middle East producers are starting to take a closer look at EOR, many are handicapped by the reliance of the technology on gas, which is sometimes used as an injectant and sometimes burned to generate another common injectant, steam. Despite massive reserves in countries like Qatar, natural gas is in short supply in most other countries in the region due to its increased usage in power generation and in industries such as petrochemicals.

Accordingly, there is a new focus on alternative technology solutions, including the use of solar power to generate steam for injecting into oilfields.

One such new technology has been developed by Glasspoint, a U.S.-based company that says it can generate steam using the sun's heat at lower cost than by burning gas. It locates the solar installations inside large commercial greenhouses, which protect the delicate panels from harsh desert winds, according to Rod MacGregor, the company's chief executive.

Reef Resources to Test Flows at Ausable Well

Reef Resources to Test Flows at Ausable Well

Tuesday, April 19, 2011
Reef Resources Ltd.

Reef Resources has agreed to complete and flow test the Ausable #5 well in SW Ontario, Canada.

A decision has been made to mechanically complete the well and to conduct flow tests on the basis of the existing data. Further analysis of electric logs and cores from the wells will continue.

Following production testing; the well will be connected to the existing central production facility and placed on production as an oil and natural gas liquids (NGL) producer. The Company's objective is to have the well on production within the next four to six weeks.

Due to the presence of extensive oil and natural gas liquids pay zones in the Ausable #5 well, the Company will now begin detailed scheduling for the drilling of the Ausable #6, #7, #8 and #9 wells and the expansion of the Ausable production facility. Currently it is hoped to complete this additional work by the end of 2011.

The Company will issue additional status reports during the testing and completion of Ausable #5 and as plans for the full Enhanced Oil Recovery and Natural Gas Liquids Program (EOR) are finalized. The Ausable reef is currently on production and is generating revenue from the initial EOR program which commenced in 4th quarter 2010 through the Ausable #1 and #4 wells.

Company President, Arnie Hansen, commented, "We see this as a turning point in the development of the Ausable Reef as the results of the well fully support our geological model and demonstrate the viability of the EOR scheme. We look forward to a busy period over the remainder of the year as we plan and execute the necessary well program."

Analysis: Another Look at The Bird

Analysis: Another Look at The Bird

Thursday, April 14, 2011
Rigzone Staff
by Trey Cowan

In a January 5, 2011 article, we dubbed the Dow Jones Transportation Index (DJT) the canary in the coal mine based on its predictive properties relative to oil price declines.

Par for the course, the recent decline in WTI crude prices was in fact preceded by a pullback in the DJT last week. Specifically, the DJT fell 3% for the week ending April 8th. Crude futures were advancing last week (improving 4%). With the last two daily declines, oil prices are now 6% below their recent peak closing price of $112.73, set last Friday on April 8th.

Given their lagging tendency, relative to the Dow Jones Transportation Index, we would expect this recent correction in oil prices to find its bottom soon.

Why this pattern occurs is really no mystery. The transportation markets are a leading indicator of the market's perception on economic activity. Higher fuel prices at some point curtail activity levels across the board, effectively diminishing demand for not just fuel but all goods and services. Should we see a dramatic pullback in the transportation index beyond the recent low set in March, barring other factors extant to macroeconomic conditions, then we would expect oil to retrace back to levels of $90 per barrel seen at onset of the year.

We are already starting to see signs that higher gasoline prices are causing a shift in consumer behavior. At the pump, gas station owners have begun to report that the frequency of customers and volume of gasoline purchases is dropping on a weekly basis. The numbers support these claims as the MasterCard Spending Pulse, which tracks sales at 140,000 gas stations, reports gasoline consumption has been falling for the past 6 weeks straight.

Back in January we warned of this phenomenon regarding demand destruction in our article "Panning Out". Here is what we said:
There is a real threshold that causes consumers to modify their driving patterns (i.e. a shrinking discretionary budget giving way to a reduction in miles driven) that could stall the current economic recovery underway.

Assuming that the average amount of annual discretionary spent per US household is approximately $1,000, then a $0.75 per gallon increase in gas prices would absorb practically all the discretionary budget for a two-car family. Using average 2010 gasoline prices as the base, this would imply that US drivers will see their discretionary budgets evaporate once gasoline prices top $3.50 per gallon.

As demonstrated in the following chart, you can see that what is occurring today corresponds with our January prediction.

Sustained energy demand destruction, in our opinion, would likely spread to other areas of the economy. So, while government officials look to higher energy prices as a means to spur innovation in alternative energy sources, the trade-off could be a derailment of the current economic recovery. While we do not have a calamity or supply disruption that at other times would merit tapping the Strategic Petroleum Reserve, a whole-hearted dismissal of utilizing this tool puts the United States' energy policy in a game of chicken with our economic recovery.