Grand Pacaraima Gold Corporation Has Acquired Controlling Interest in Petroleste Ventures, LDA

VERNON, BC, Sep 23, 2010 (MARKETWIRE via COMTEX) -- Grand Pacaraima Gold Corporation (pinksheets:GPGD) announced today that they have acquired controlling interest in Petroleste Ventures, LDA, a Timor Leste,(formerly East Timor) Company, through GPGD's wholly owned subsidiary Jasmine EKA Karya, Inc, a Texas Corporation. Jasmine's board of directors finalized the acquisition of Petroleste Ventures LDA, with the signing of the "Agreement and Plan of Merger/Acquisition."
David Nolan, CEO of Jasmine, said this new alliance, with their Timor Leste partner, Petroleste Ventures, LDA, will greatly enhance the Company's ability to move forward with the projects now under negotiations within the country of Timor Leste. This would include the projects related to the petrochemical industry and other infrastructure projects within the country.
GPGD Board of Directors commented, "This new acquisition will be a positive move for GPGD's shareholders. We are committed to providing increased equity and shareholder value on a continuing basis through the continued acquisition of new assets, mergers, acquisitions, expansion and development of our existing holdings. This acquisition has been a significant step toward meeting those goals."
About Jasmine EKA Karya Inc. Jasmine, a US Corporation is headed by David Nolan, as its Chief Executive Officer (CEO). Jasmine was formed as a commodity trading company dealing in the petroleum industry. Its main emphasis as a General Contractor is petrochemical infrastructure in construction of drilling rigs, refineries, ports and energy related projects.
About Petroleste Ventures, LDA. Petroleste was organized under the laws of Timor Leste, (formerly East Timor) with its ownership including local Timor Partners, under the guidance of Mssr. Blausius Pereira and Francisco Guterres. The Company's main interest is in import and export of commodities to include oil and refined petrochemical products, energy infrastructure within the Country of Timor Leste, related to ports, refineries, oil and gas terminals and other infrastructure projects to improve the Country's transportation, natural and human resourse needs.
About Grand Pacaraima Gold Corp. (GPGD) -- www.GPGD.PK The Company and Management's new emphasis is on energy projects, mergers and acquisitions related to the energy industry.
Forward-Looking Statements: Certain statements contained in this press release are forward-looking statements that involve risks and uncertainties. The statements contained herein that are not purely historical are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended

What Is Tight Gas, and How Is It Produced?

While conventional natural gas streams from the earth relatively easily, unconventional gas finds are more difficult to develop and more costly to produce. As technologies and skills improve, unconventional gas is a variable concept because some finds may become more easily or economically produced over time, no longer making them unconventional. Right now, there are six main types of unconventional gas, including deep gas, gas-containing shales, coalbed methane, geopressurized zones, Arctic and subsea hydrates, and tight gas.

Major Tight Gas Reserves in the USSource: EIA, www.eia.doe.gov

Unconventional natural gas deposits are likely to account for much of the world's remaining reserves. According to the EIA, there is more than 309 Tcf of recoverable tight natural gas deposits in the US, which represents some 17% of the total natural gas reserves in the country.
Helping to boost interest in developing technologies that can overcome the challenges of producing unconventional gas resources in the United States, the Natural Gas Policy Act offers incentives to companies exploring for and producing unconventional gas plays.

What Is Tight Gas?

Tight gas refers to natural gas reservoirs locked in extraordinarily impermeable, hard rock, making the underground formation extremely "tight." Tight gas can also be trapped in sandstone or limestone formations that are atypically impermeable or nonporous, also known as tight sand.

Impermeable Pores in Tight Gas FormationSource: USGS, www.energy.usgs.gov

While a conventional gas formation can be relatively easily drilled and extracted from the ground unassisted, tight gas requires more effort to pull it from the ground because of the extremely tight formation in which it is located. In other words, the pores in the rock formation in which the gas is trapped are either irregularly distributed or badly connected with overly narrow capillaries, lessening permeability -- or the ability of the gas to travel through the rock. Without secondary production methods, gas from a tight formation would flow at very slow rates, making production uneconomical.
While conventional gas formations tend to be found in the younger Tertiary basins, tight gas formations are much older. Deposited some 248 million years ago, tight gas formations are typically found in Palaeozoic formations. Over time, the rock formations have been compacted and have undergone cementation and recrystallisation, which all reduce the level of permeability in the rock.
Typical conventional natural gas deposits boast a permeability level of .01 to .5 darcy, but the formations trapping tight gas reserves portray permeability levels of merely a fraction of that, measuring in the millidarcy or microdarcy range.
In order to overcome the challenges that the tight formation presents, there are a number of additional procedures that can be enacted to help produce tight gas. Deviating drilling practices and more specific seismic data can help in tapping tight gas, as well as artificial stimulation, such as fracturing and acidizing.

Developing Tight Gas

One of the most important aspects of drilling for any petroleum is predetermining the success rate of the operation. Operators do not just drill anywhere. Extensive seismic data is gathered and analyzed to determine where to drill and just what might be located below the earth's surface.
These seismic surveys can help to pinpoint the best areas to tap tight gas reserves. A survey might be able to locate an area that portrays an improved porosity or permeability in the rock in which the gas is located. Should wells directly hit the best area to develop the reserve, costs of development can be minimized.
Most tight gas formations are found onshore, and land seismic techniques are undergoing transformations to better map out where drilling and development of these unconventional plays. Typical land seismic techniques include exploding dynamite and vibroseis, or measuring vibrations produced by purpose-built trucks. While these techniques can produce informational surveys, advancements in marine seismic technologies are now being applied to land seismic surveys, enhancing the information available about the world below.
Not only providing operators with the best locations for drilling wells into tight gas formations, extensive seismic surveys can help drilling engineers determine where and to what extent drilling directions should be deviated.

Directional DrillingSource: MacKenzie Gas Project, www.mackenziegasproject.com

While vertical wells may be easier and less expensive to drill, they are not the most conducive to developing tight gas. In a tight gas formation, it is important to expose as much of the reservoir as possible, making horizontal and directional drilling a must. Here, the well can run along the formation, opening up more opportunities for the natural gas to enter the wellbore.
A common technique for developing tight gas reserves includes drilling more wells. The more the formation is tapped, the more the gas will be able to escape the formation. This can be achieved through drilling myriad directional wells from one location, lessening the operator's footprint and lowering costs.

Production Stimulation

After seismic data has illuminated the best well locations, and the wells have been drilled, production stimulation is employed on tight gas reservoirs to promote a greater rate of flow. Production stimulation can be achieved on tight gas reservoirs through both fracturing and acidizing the wells.
Fracturing, also known as "fracing," a well involves breaking the rocks in the formation apart. Performed after the well has been drilled and completed, hydraulic fracturing is achieved by pumping the well full of frac fluids under high pressure to break the rocks in the reservoir apart and improve permeability, or the ability of the gas to flow through the formation.
Additionally, acidizing the well is employed to improve permeability and production rates of tight gas formations. Acidation involves pumping the well with acids that dissolve the limestone, dolomite and calcite cement between the sediment grains of the reservoir rocks. This form of production stimulation helps to reinvigorate permeability by reestablishing the natural fissures that were present in the formation before compaction and cementation.
Furthermore, deliquification of the tight gas wells can help to overcome some production challenges. In many tight gas formations, the reservoirs also contain small amounts of water. This water can collect and undermine production processes. Deliquification is achieved in this instance through artificial lift techniques, such as using a beam pumping system to remove the water from the reservoir, although this has not proven the most effective way to overcome this challenge.
Engineers continue to develop new techniques and technologies to better produce tight gas. Through their efforts, maybe one day, tight gas will no longer be considered an unconventional play.

Musings: Gas Shales: Good News, Bad News

The Pennsylvania Department of Environmental Protection has released Marcellus gas shale production data for the 12 month period from July 1, 2009 through June 30, 2010.  The 632 producing Marcellus wells released 180 billion cubic feet of gas, more than double annual natural gas production in Pennsylvania from years before gas shale exploration began.  The data was made public in response to changes to the state’s oil and gas disclosure law that mandates well-by-well production totals be released every six months.  The revision to the disclosure law eliminated the provision that would have kept this data confidential for five years.

John Harper, chief of the minerals resources division of the Pennsylvania Geological Survey, pointed out to The Scranton Times-Tribune that Marcellus wells that produced gas in the last fiscal year averaged almost two million cubic feet per day (cf/d) and was “a lot better” than the earliest dozen or so Marcellus wells in the state that only averaged 89,000 cf/d.

Marcellus gas produced last year was worth about $720 million, which is a large number but less than the cost of drilling and developing the wells

Dr. Terry Engelder, professor of geosciences at Penn State University and a student of the Marcellus gas shale, said the production data shows that expected ultimate recovery from the wells will exceed industry predictions.  He compared the average cumulative production for Marcellus horizontal wells in the 5-county core area of the North Central and Northeast part of Pennsylvania to predictions made to investors in 2008 by Chesapeake Energy (CHK-NYSE).  While the production data is better than expected, Dr. Engelder also noted that the Marcellus gas produced last year was worth about $720 million, which is a large number but less than the cost of drilling and developing the wells.  It is these negative economics that are beginning to play havoc with the profitability of the E&P companies active in the gas shale formations.

We are now seeing numerous producers indicating they are actively reducing or planning to reduce their rig counts in the gas shale formations around the country in response to the poor well economics – low natural gas prices and high drilling and well completion costs.  Without a large volume of natural gas liquids in shale gas production, current gas prices make these wells uneconomical.  As Dr. Engelder pointed out with the Marcellus data, producers are destroying capital by continuing to drill wells in this low gas price environment.  Drilling activity in the gas shale formation continues to be driven by the need for producers to secure their leasehold positions with producing wells.  Until drilling driven by the gas shale land rush leasing environment of the past three years is over, there is little reason to expect much of a rig count decline in the near term.  Most likely the end of the lease-driven drilling will happen in 2011, unless operators exhaust their financial resources and are forced to cut their drilling activity.

All the data supplied by the companies must be delivered along with a statement attesting to its accuracy signed by a "responsible corporate officer" under penalty of the law

The bad news for the industry may have arrived in letters sent by the Environmental Protection Agency (EPA) to nine U.S. companies involved in providing fracturing services to the E&P industry.  The letters asked for substantial detailed information such as: a list of the chemicals and their composition used in hydraulic fracturing fluid formulations; all data and studies related to the human health and environmental impacts and effects of these chemicals; the policies, practices and procedures employed in fracturing operations; and information about all hydraulic fracturing jobs performed within the prior 12 months.  All the information is to be supplied voluntarily.  If insufficient data is provided, the EPA will consider legal actions to secure the necessary data it feels it needs.  In addition, all the data supplied by the companies must be delivered along with a statement attesting to its accuracy signed by a “responsible corporate officer” under penalty of the law.  Increasingly the federal government is using the power of perjury as a way to intimidate corporate, and especially energy company, officers.
The purpose of this data request is, according to the letter, “To help the EPA evaluate the potential impact of hydraulic fracturing on drinking water quality and public health.”  The EPA study is in addition to the investigation of the hydraulic fracturing process by Congress.  Many people in the industry are concerned that the EPA study is the first step toward the agency gaining more control over fracturing regulations, even though many Washington observers remain convinced that Congress will not overturn the ruling exempting hydraulic fracturing operations from regulation under the Clean Water Act.  It may be a while before the EPA study is completed, but until it is and the industry is cleared, we will keep our fingers crossed.

Analysis: Shale Gas to Play Long-Term Role in Global Gas Demand

Long-term growth in shale gas production is expected to play an important role in shaping North American, European and Asian natural gas demand, according to a new report released by Ernst & Young at the World Energy Congress.

"The unconventional natural gas business may have already changed the overall supply and demand balance in North America, and perhaps globally," said Barry Munro, Leader of Ernst & Young's Canadian oil and gas practice. "It's possible we could be onto something big, but there are many underlying uncertainties including growing environmental concerns, technology challenges, water availability, and land issues."

The report, The Global Gas Challenge (PDF), finds that while unconventional gas resources have the potential to fundamentally impact global supply and demand balances, the long-term viability is still maturing. On the demand side, uncertainties exist around the state of economic recovery and expanded long-term uses for new natural gas production. For supply, more clarity is needed in terms of policies that support reduced carbon emissions - something that expanded natural gas use will achieve.

According to the International Energy Agency (IEA), global gas demand is forecast to grow by 1.5% per annum through to 2030, with the majority of the growth coming from non-OECD [Organization of Economic Cooperation and Development] countries. However, actual gas demand growth will likely be influenced by some of these unpredictable factors.
"At a global level, the immediate risk is that the current low price environment dissuades natural gas players from investing in new projects," said Munro, "This initiates a cycle beginning with underinvestment by E&P companies, and ultimately resulting in not enough gas to meet demand."

According to the Ernst & Young report, continued demand for natural gas in the developing countries will support growth in global gas demand. Abundant supply and favourable carbon emissions relative to oil and coal should also help to attract favourable regulation. Asia is expected to drive bulk of growth, along with India and the Middle East.
The question is whether the success of unconventional resources in North America and announced expenditure to create liquefied natural gas (LNG) facilities can be repeated on global basis. Most importantly, pricing needs to be robust enough to encourage capital investment in projects. Prices are currently low as a result of an abundant supply of natural gas.

According to Munro, the current supply/pricing environment has also changed economics for conventional LNG projects in Canada, and arguably for every LNG project across the world. Again, challenging economics and restricted access to capital will alter any expected LNG supported demand growth in many regions.
"A truly global gas market will not emerge until there is greater flexibility in gas supplies, increased transportation between regions and more gas-on-gas competition," Munro said. "'It's time to start thinking about natural gas from a different perspective, and as a viable long term energy source for multiple uses."

Regional Challenges

Proved U.S. shale gas reserves at the end of 2008 were estimated by the U.S. Department of Energy (DOE) at 32.8 Tcf, a little more than 13 percent of total U.S. natural gas reserves. However, proved reserves of shale gas are though to be relatively small in comparison to total technically recoverable reserves.
The main factor likely to inhibit the projected growth in shale gas production is new environmental legislation. In particular, regulators and policy makers are concerned about possible threats to local water supplies and public health as a result of hydraulic fracturing. Currently, a comprehensive study is being undertaken by the U.S. Environmental Protection Agency (EPA) into the impact of hydraulic fracturing on water quality and public health. Investment in shale gas developments may dry up if hydraulic fracturing were to be outlawed or significantly limited as a result of the findings of the EPA study.

Current U.S. shale production growth is depressing short-term gas prices in North America. Prospects for continuing or even more rapid growth in production, both in North America and potentially elsewhere, are also pressuring mid- and longer-term price assumptions. In its latest long-term energy forecast, the DOE expects shale gas production to reach more than 12 Bcf/d by 2020, and almost 17 Bcf/d by 2035.
In Europe, shale and other unconventional gas resources have been identified in Australia, France, Germany, Hungary, Italy, Netherlands, Poland, Romania, Spain, Sweden, Switzerland and the UK. Land and license acquisition and early-stage exploration is underway in a number of these countries.

However, a number of challenges to exploiting European shale gas potential exist, including Europe's higher population density, that would make many stages of the operation more difficult. Opponents may also seek to highlight any examples from the U.S. of environmental impairment in an attempt to block developments. In addition, sub-surface mineral rights tend to be owned by the state in Europe and there is a dearth of drilling rigs and other equipment required for shale gas development. The lessons learned in extracting gas from shale, a complicated process, also may not be directly transferable to Europe.
The global gas battleground is still likely to be Asia, with increasing LNG supply capabilities into the region from the Middle East, Southeast Asia and Australia, along with increasing pipeline capacity into Asia, from both the Caspian and Russia. The next tranche of LNG developments in Australia is underway with eight projects under development in Western Australia and more planned. However, capital costs for LNG plants have at least doubled over the last five years, leaving Australia as one of the highest cost locations for new LNG projects supplying the Asia-Pacific market. The country's status as an attractive destination for inbound investment has been shaken by the controversy over plans for the introduction of a resource super profits tax, which have since been shelved and replaced by a proposed mineral resources rent tax.
China will be a primary customer of future LNG supplies from Australia as Chinese gas demand is forecast to more than double by 2020, according to the IEA. The Chinese government is seeking to increase gas usage due to environmental concerns and need to reduce dependence on other fuel sources. The projected increase in gas demand will provide impetus to the development of China's shale and coal deposits.

While China's yet unquantified shale resources could rival those of the U.S., the government will need to allow more foreign investment and gradually shift to market pricing. Investment to extend the gas pipeline infrastructure is needed to facilitate the transport of gas across provinces. Present gas infrastructure in China is limited, with most producing assets supplying gas to local markets.

Darwin set to be floating LNG hot-spot

September 13, 2010 - 1:49PM

Darwin is set to be "the floating LNG capital of the world", Northern Territory Minister for Primary Industry, Fisheries and Resources Kon Vatskalis says.
Speaking at the Australian Pipeline Industry Association Annual Convention in Darwin on Monday, Mr Vatskalis said the top end looked likely to become a hot-spot for floating liquefied natural gas (LNG) developments.
"Within 10 years, I suggest to you that we could have five to seven floating LNG projects under development or in production, and the Northern Territory will be the floating LNG capital of the world," he said.
 

Floating LNG is increasingly being considered by energy companies seeking to commercialise remote or `stranded' natural gas fields, with processing taking place offshore on large vessels, rather than being piped onshore to a plant.
Royal Dutch Shell's Prelude field, some 475 kilometres north-northeast of Broome, is set to be the world's first floating LNG development when it begins production in 2016.
Also, Woodside Petroleum Ltd wants to use a floating LNG platform for its Sunrise project in the Timor Sea, despite the Timor Leste government calling for an onshore development.
Piping the oil to East Timor would be high cost and carried significant technical risks, Woodside said earlier this year.
"This development plan has now been submitted to the Australian and Timor Leste regulatory authorities and we will see how this progresses in due course," Mr Vatskalis told the conference on Monday.
"In addition to Sunrise, we have the Bonaparte floating LNG project proposed by the GDF Suez/Santos alliance for the Petrel, Tern and Frigate gas fields, some 250km to 300km to the south west of Darwin.
"This project is currently in pre-FEED (front end engineering design) and is targeting first production in 2018.
"A number of other smaller, stranded gas fields in the Timor Sea to the north and to the west of Darwin are also promoted as being under consideration for floating LNG development by companies with good credentials to deliver projects of this nature."
In addition to being the site for several floating LNG proposals, the top end had a win in 2008, when Japan's Inpex chose to pipe gas from its $20 billion plus Ichthys project, offshore Western Australia, to an onshore plant at Darwin.
"The Ichthys LNG project is moving toward a ... final investment decision in the fourth quarter of 2011," Mr Vatskalis said.
"Construction is set to commence in early 2012 and the first LNG cargo is planned for early 2016."

ENI Australia Announces Timor Sea Farm-in Opportunity

ENI Australia Ltd is seeking partner(s) to farm-in to an oil exploration opportunity with outstanding upside potential - Timor Sea offshore Timor-Leste Blocks S06-01, S06-02, S06-03, S06-04 & S06-05

Project Overview:
Eni is offering up to a 30% working interest in five exploration blocks in the Timor Sea offshore Timor-Leste.

Blocks S06-01 to S06-05 cover 10,000 km2 offshore Timor-Leste with blocks S06-03, 04 and 05 overlying the northern Bonaparte Basin and Timor Trough off the north coast of Australia.

Over 2.5 billion barrels of mean oil reserves has been identified in Blocks C, E and H alone. Recent interpretation integrating new 2D and 3D seismic data has identified a number of large structures in 500-2,000 m of water. Two of the largest Jurassic prospects in Block C targeting up to 500 million barrels of oil will be drilled in late 2010 and early 2011.

Eni is offering up to 30% equity in this exciting under-explored area. With close proximity to known oil and gas fields and the recent interpretation of the Albacora 3D, these blocks offer a high level of prospectivity and have the potential to significantly upgrade your reserves position.

The upcoming drilling program planned to commence late in 2010, is targeting two of the largest Jurassic prospects in Block C with potential for 500 million barrels of oil.

The first well to be drilled will be Cova-1, a Jurassic tilted fault block structure.