ExxonMobil signs EPSA IV agreement for exploration in offshore Sirte Basin

Exxon Mobil Corp.’s subsidiary, ExxonMobil Libya Ltd., has signed an Exploration and Production Sharing Agreement with Libya’s National Oil Corp. (NOC) to initiate exploration activity offshore Libya in the Sirte Basin.

The agreement includes 4 blocks located in Contract Area 20, approximately 100 miles off the Libyan coast, which were awarded to ExxonMobil in the third round of EPSA IV licensing in December. The contract area comprises 2.5 million acres and is situated in water depths ranging from approximately 4,000 feet to more than 6,500 feet.

“We are pleased that we were awarded a contract area for exploration,” said Phil Goss, president and general manager of ExxonMobil Libya Ltd. “ExxonMobil has a long history of successful achievements in Libya and we look forward to working together with the NOC and Libyan government for renewed success with these new areas.”

Elsewhere in Libya, ExxonMobil is in the very early stages of an exploration program in Contract Area 44 in the offshore Cyrenaica Basin, which was awarded to the company in the second round of EPSA IV licensing in 2005. To date, the company has completed an Environmental Impact Assessment (EIA), met with local stakeholders, and is conducting a 2D seismic acquisition program.

Operational debut for HNNG’s nitrogen removal technology

HNNG Development LLC has started the company’s first Nitrogen Rejection Unit (NRU), a proven technology for the removal of nitrogen from natural gas.

The installation and start-up of the unit for Agape Energy Alliance LLC, in Garfield County, Okla. is a critical point in HNNG’s development as it is the first application to go live since the company began commercializing its solvent-based physical absorption technology in November 2005. Under the terms of the agreement, having completed the installation and start up of the project, HNNG will lease the nitrogen removal unit to Agape.

The unit utilizes the “AET” process, licensed to HNNG by Advanced Extraction Technologies Inc., to unlock the economic potential of high nitrogen natural gas reserves that otherwise could not be brought to market due to associated compliance and quality issues. The unit installed for Agape is designed to treat natural gas which has a nitrogen content of up to 50% and is capable of processing up to 1 million cubic feet per day of natural gas, bringing it comfortably within the project’s pipeline quality specifications.

Dwight Bushman at Agape said, “The team at Agape is delighted to be working with HNNG Development on this project. We are particularly excited by the flexibility of the technology, in that the modular NRU can be mobbed to a new location once the initial targeted reserves are depleted. This will enable us to take full advantage of already identified additional wells in the area for drilling, at a relatively low cost. We look forward to realizing the full operational and financial benefits of HNNG’s technology over the coming months.”

Commenting on the start-up of the NRU at Agape Jeff Pendergraft, chairman and CEO of HNNG said: “The commissioning process has demonstrated fantastic results for this proven technology and it is with great excitement that we wait for the full benefits of our nitrogen rejection unit to be experienced by Agape.”

“The volume of business enquiries that HNNG is now attracting makes us even more confident that our nitrogen technology satisfies a genuine and growing market need. As demand for natural gas increases exponentially and secure ‘greenfield’ sources become harder to exploit, we see the launch of our Agape unit as a landmark in the commercialization of economically-stranded high nitrogen reserves.”

Petrobras’ Cottonwood field starts producing in the US

Petrobras, a Brazilian international energy company, through its wholly-owned subsidiary Petrobras America Inc., has brought online the first well of the new Cottonwood field. Initial output is 1.1 million cubic meters of gas and 4,000 barrels of light oil (condensate) per day. A second well started production in the end of February, boosting gas production to 2 million cubic meters per day. Together, the two wells will take the field production to 20,000 boe/d.

As a result, Cottonwood will be the biggest Petrobras America field in production. This is the first deepwater field Petrobras has developed and put into production abroad as an operator. The field is also an example of the integrated work of specialists from several of the company’s units in Brazil, with Petrobras America’s team, integrating Petrobras’ experience and technology with the Gulf of Mexico’s market practices. The outcome of this joint work has brought the project from blueprints into operation 12 months after the company’s executive board approval.

The Cottonwood field is located in Garden Banks quadrant block 244, in the American sector of the Gulf of Mexico, in a water depth of 670 meters. This is the company’s first field to use submarine equipment and systems capable of operating under high pressure. The field’s two submarine completion wells are interconnected to a third-party fixed production platform, located 27 km away, via two production pipelines and a chemical product control and injection umbilicalcable. This event marks Petrobras’ return, as an operator, to Gulf of Mexico production fields.

Rising production costs cause diminishing returns for natural gas producers

In the first-ever study of all wells drilled in 2005, a multi-client analysis by Cambridge Energy Research Associates (CERA) and IHS found that despite record high natural gas prices in recent years, fewer reserves are being added for every dollar of exploration and production activity, and higher costs are undermining the economics of an increasing number of wells. The study also identified the dramatic shift toward “unconventional” gas production which now accounts for a quarter of total output.

The analysis of the cost and production data for the 48,000 wells completed in all 50 North American natural gas basins (232 individual plays) in 2005, found that capiral costs alone (expluding operating costs, royalties, and return) ranged from $1 per Mcf of reserves to over $6 per Mcf. The weighted average all-in cost ranged from below $4.00 per Mcf to over $12 per Mcf. Judged against the record prices of 2005, which averaged $8.80 per Mcf at Henry Hub, over 6% of basins had costs high enough that they would fail to achieve a 10% rate of return-on-investment.

“Record prices in 2005 triggered tremendous response in drilling by gas producers, leading to nearly decade-high reserve additions of 26.4 trillion cubic feet and added production of 14.7 billion cubic feet that year,” said J. Michael Bodell, CERA’s director of upstream gas strategies. “Nevertheless, despite a nearly threefold increase in the number of rigs deployed to drill natural gas wells over the past decade, North American gas production has remained stubbornly flat and the cost of new gas supply has risen substantially due to higher drilling and operating costs and, most significantly, declining average well productivity and initial production rates.”

In the CERA/IHS study, costs were calculated utilizing the entire IHS catalogue of North American well and production information. Capital and operating costs were calculated for each of North America’s 232 plays, and production profile of each play was uniquely modeled.

“The ultimate economic performance of the wells drilled in 2005 will depend on the trajectory of market prices and many other factors related to well production. However, viewed in the context of the market and cost environment at the time of drilling, it is clear that rising service costs have begun to take away much of the margin in many wells and plays despite historically strong market prices,” said Bodell. “Conventional wisdom is that all producers are enjoying a windfall from higher prices; however, the less visible cost of gas production has moved up as dramatically as market prices,” he added.

“Record well completions are being totally offset by declining per-well productivity, so price expectations will be central for motivating continued strong drilling,” Bodell said. “The fundamental driver of the North American E&P challenge is the relative naturity of the natural gas resource base. Although gas resources are available - and some are off limits due to access issues - and new plays are being identified and developed, many of these resources are deeper, smaller, technically more challenging, or more distant from markets.”

As a whole, E&P companies are developing smaller resources and facing higher costs, thus resulting in unit costs moving to a higher range. Within this trend though, many regions, on the other hand, have very strong margins and provide equity returns well beyond 10%. “The E&P companies that have shifted their portfolios to include these lower-cost resources, particularly the early movers, are recognizing substantial cost advantages,” Bodell added.

The study also pointed out the higher levels of drilling required to replenish gas lost from declines in production from wells drilled in past years. “If no further drilling occurred after 1999, North American wet gas production would have fallen to about 29 bcf by 2006, or less than half the production level in 1999,” Bodell observed.

The study found that a combination of higher prices and improved drilling technology has sped up the development of unconventional resources which accounted for 23% of total North American gas production in 2005 compared to 11% in 1995.

These resources have been known about for decades, but were generally uneconomical in terms of development. Because unconventional wells access larger deposits than their conventional counterparts, they accelerate reserve base growth and provide higher production over a 20-year productive life.

“On the question of whether unconventional gas is cheaper or more expensive than conventional resources, we found there is no consistent answer. Unconventional production basins are distributed through out the cost spectrum among the lowest and the highest cost resources, and not overweighted on either the low or high end,” said Bodell. “This means that the industry is investing heavily in unconventional resources moving from the easier plays and basins to resources that represent more challenging opportunities. These more challenging resources may come at a cost that has the potential to put them in direct competition with imported LNG,” he continued.

Cambridge, Mass.-based CERA, an IHS company, is an advisor to energy companies, consumers, financial institutions, technology providers, and governments.

IHS is a global provider of critical technical information, decision-support tools and related services to customers in a number of industries including energy, defense, aerospace, construction, electronics, and automotive.

BPZ Energy initiates testing operations

BPZ Energy has begun testing on the recently drilled CX11-21XD well in the company’s Corvina gas field off the coast of Peru.

The company completed all pressure integrity tests of the well, replaced mud by completion brine in the wellbore, and connected the gas flare and surface equipment to the well. Consequently, the testing phase was initiated with a series of activities including the insertion of explosive charges in the tubing-conveyed perforating guns, checking and assembling of the 3 1⁄2” pipes to be used as production string during the tests, and installation of the corresponding blow-out preventers.

The company will conduct several drill stem tests in the prospective Upper and Lower Zorritos formations. The first DST will be conducted on the Lower Zorritos formation consisting of high permeability gas sands with limited quantities of mobile water. The second will be conducted in the bottom section of the Upper Zorritos formation. This second DST is targeting lesser quality sands with larger quantities of mobile water. A successful test could then help validate the vast majority of the prospective pay identified through petrophysical analyses. The third and final DST will be conducted in the top section of the Upper Zorritos. This section has highly permeable sands with no mobile water, thus representing potentially the best quality gas sands.

The company expects testing to take about 2 to 4 weeks. The tests are designed to provide the company and its independent reserve engineers with data on actual gas pay and well deliverability, leading to the quantification of reserves in the Corvina gas field.

Houston-based BPZ Energy is an oil and gas exploration and production company with properties in northwest Peru and southwest Ecuador.

Petroleum Place and Tristone restructure

Tristone Energy Services Inc. has reached an agreement to restructure its businesses. This involves the separation of its investment banking, corporate finance, capital markets, and energy asset acquisition and divestiture divisions, currently operating under the name of Tristone Capital, from its software, data and services, operating under the name of P2 Energy Solutions, and its property marketplace businesses, currently operating under the name of The Oil & Gas Asset Clearinghouse.

As part of the restructuring, the officers and employees of Tristone Capital will become the owners and operators of the investment banking, corporate finance, capital markets, and energy asset acquisition and divestiture businesses under a newly incorporated company known as Tristone Capital Global Inc. and will cease to be officers, employees, and shareholders of Tristone Energy Services.

P2 Energy Solutions and The Clearinghouse will continue under its current management. The parent company of these business units, Tristone Energy Services, will be renamed P2 Energy Services. Approximately 80% of the equity in P2 Energy Services equity ownership will thereafter be held by Petroleum Place and the balance substantially in the hands of the management of the businesses.

Ken Olive, president and CEO of The Clearinghouse said, “We are very pleased with the reorganization and believe this to be an extremely positive plan for our clients and shareholders. It enables each of our businesses to focus on the things that we do best. The completion of the spin-out of Tristone allows The Clearinghouse to refocus on our core businesses with emphasis on delivering the highest level of support to our customers by paying particular attention to the details of each asset.”

Tristone Capital Global will continue to offer global investment banking, corporate finance, capital markets, and energy asset acquisition and divestiture services to energy companies worldwide. Tristone Capital Global owns and operates Tristone Capital Inc.