Solimar Energy Limited

ASX : SGY
TSX VENTURE : SXS


Solimar Energy Limited

November 21, 2012 05:00 ET

Solimar Production Testing Lighter Oil Pool in Kreyenhagen Oil Field

MELBOURNE, AUSTRALIA--(Marketwire - Nov. 21, 2012) -

NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES

Solimar Energy (ASX:SGY)(TSX VENTURE:SXS) ("The Company") provides the following update for the Company's 100% owned Kreyenhagen shallow oil field redevelopment project in the San Joaquin Basin, California. As a follow-up to the previous announcements of establishment of production testing and a 3,101% increase in Contingent Recoverable Resource (C2 - Best Estimate) attributable to the Temblor Sandstone, the Company now has initiated long term primary production in the field and confirmed the presence of a potentially significant down-dip, lighter oil pool.

  • Based on the encouraging initial production testing of the Temblor Sandstone which has produced at unstimulated primary production rates of 4-15 BOPD, the Company has put the 4-33 well on a long term production test.

  • Integration of the newly obtained well data with the Temblor sandstone geologic model confirms that the 4-33 well is producing from a down-dip zone of lighter oil (17° API gravity) that has not previously been produced. The identification of this zone offers the potential for multiple additional locations along strike and for potential exploitation by higher flow rate deviated or horizontal wells.

  • The Company is planning by year end to production test the Temblor oil reservoir in a third well (2-32), which is currently suspended awaiting re-entry, in the northwest section of the field.

  • As previously reported, the results of the 4-33 well means that the Company now has the opportunity to realize proven reserves in the field through primary production. In parallel, drilling of appraisal wells is expected to significantly increase again the Contingent oil Resource in the field (4.2 mmbo (best estimate), 2.4 mmbo (low estimate), and 6.2 mmbo (high estimate) from the current area of 115 acres to up to 500 acres. There is also now improved confidence in the applicability of the cyclic steam ("Huff and Puff") program which is to be initiated in Q1 2013.

Will Satterfield, CEO of Solimar, commented "We are pleased that the initial round of production testing in the Temblor sandstone has confirmed a new down-dip lighter oil pool in the field area. Based on the well results we are increasingly confident in the applicability of steam enhanced production and reserve growth and are actively investigating the potential for primary production in conjunction with the steam flood."

COMPETENT PERSONS STATEMENT: The information in this report has been reviewed and signed off by Will Satterfield B.S., M.A. who is a petroleum geologist with over 24 years of relevant experience within the oil and gas sector.

Kreyenhagen Field Temblor Production Testing

On October 15 the Company announced the initiation of production testing of the Temblor Sandstone at the Kreyenhagen Field. This involved the testing of the shallow Temblor sandstone heavy oil zone which was not previously tested in wells drilled in 2007 by an earlier operator to a deeper zone (Avenal sandstone). The wells were previously completed with 7 inch casing and cemented, which provided a unique opportunity for the Company to carry out zonal testing of Temblor pay zones to better understand reservoir and fluid properties. All but one of the vintage field wells were drilled and completed with an uncemented slotted liner across the entire Temblor pay zone preventing an accurate analysis of intra reservoir zones and oil quality. The Kreyenhagen Field contains an approximate 200 ft gross oil pay zone, however study of the older well logs and sample descriptions suggested the presence of intra Temblor sandstone zones with better reservoir quality and oil characteristics that could potentially be exploited via zonal completions or horizontal wells, resulting in enhanced production rates for both primary and thermal production. The purpose of the 2012 production testing was to investigate the above premises to further reduce reservoir uncertainty leading up to the cyclic steam pilot in 2013.

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While the 1-33 well tested the core of the field and recovered 14° API oil as expected, the 4-33 well was fortuitously located down-dip of the main field in an area with no previous production. Core descriptions from a nearby well (Schrock-1), drilled in 1927 and not tested, suggested that a light oil zone was separate and segregated from the main pool section. Also, mud log oil and gas show descriptions in the 4-33 well suggested a similar conclusion. Testing results from the 4-33 well unequivocally confirmed the Company's premise of a down-dip lighter oil pool. The well contains net pay of 130 feet with sidewall core porosity and permeability of 32% and 500-1,100 md (millidarcies) respectively. The well began production at a rate >15 bopd from perforations between 850-1,030 ft before stabilizing after a few weeks at 4-5 bopd with a water cut of 35%. The well is currently producing to a temporary production facility.

Based on these encouraging results, the Company is in the process of preparing to test the Temblor Sandstone in the 2-32 well and investigating running a mini-frac job on one or more of the wells.

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Implications of Production Testing Results

The Company is very encouraged from the initial testing results from the shallow Temblor sandstone reservoir. The results illustrate that a previously unrecognized lighter gravity oil pool could be developed via primary production. It is envisioned that the pool could be a low cost, shallow primary development via vertical or horizontal wells, which the Company is actively studying. As shown in analogous settings in the San Joaquin Valley, along strike horizontal wells targeting a down-dip oil wedge could be used to provide a near term primary production boost, while the steam flood is being implemented. The Company is also looking to further enhance the well productivity through small frac jobs that are proven to work in similar, shallow reservoirs in the area.

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As previously reported, laboratory analysis of the 17.3° API crude oil sampled from the 4-33 well shows an oil viscosity profile which is significantly lower (better) than previously modeled. At current reservoir temperature, the measured oil viscosity is 125 cP (centipoise) as compared to the modeled 800 cP, representing an 84% positive decrease. At an expected steam enhanced reservoir temperature of 300° F (Fahrenheit) the measured oil viscosity is 3 cP (centipoise) as compared to the modeled 6 cP, representing a 50% positive decrease. As a result, under steam stimulation, the oil would be more fluid than previously modeled which would result in increased oil production rates and recoveries. This translates to lower water cuts versus time and versus percent recovery compared to previous modeling. Ultimately this will equate to higher oil recoveries. For reference, a recovery factor of up to 60% is reported for the Temblor sandstone under steam enhanced development at the analogous, nearby Coalinga Field. Recovery factors modeled by Sproule as part of the Contingent Resource determination at Kreyenhagen Field are 10% (low estimate), 35% (best estimate), and 60% (high estimate). The combination of shallow depths, bedding dip of 35-40°, and favorable reservoir and oil quality creates an ideal setting for an anticipated economic thermal recovery project in the Temblor Sandstone at Kreyenhagen Field.

To view the figure associated with this section of the press release, please visit the following link: http://media3.marketwire.com/docs/SEImage004.jpg

On October 29th the Company announced an increase in contingent recoverable resource in the 100% owned Kreyenhagen shallow field in the San Joaquin Basin by 3,101%. The 4.2 mmbo (best estimate) of oil was delineated within a 115 acre portion of the 500 acre discovered and undiscovered field area.

For reference and as previously reported, total contingent recoverable oil for the Temblor Sandstone in the limited part of the field studied is 4.2 mmbo (best estimate), 2.4 mmbo (low estimate), and 6.2 mmbo (high estimate)*. The Contingent resource is taken from the total discovered oil in place for the Temblor Sandstone of 23.8 mmbo (best estimate), 19.0 mmbo (low estimate), and 29.0 mmbo (high estimate). Undiscovered total oil in place for the Temblor Sandstone is 24.1 mmbo (best estimate), 11.8 mmbo (low estimate), and 50.1 mmbo (high estimate). With the initiation of the cyclic steam pilot in Q1 2013 and further primary production, the Company anticipates reporting proven reserves in 2013. In addition, further Contingent Resource is anticipated to be confirmed with appraisal drilling within the DOGGR defined field boundary in 2013.

*Reference: Contingent Resource Assessment of the Temblor Formation in the Kreyenhagen Field Administrative Boundary Lease for Solimar Energy Limited (as of 31 July, 2012) - By Sproule Unconventional Limited. This report was highlighted in a release to the ASX and Canada on 29 October, 2012. A copy is on Solimar Energy's website under "Investor Centre" and "Resources Reports".

Reader Advisory: Potential resource estimates and forward-looking statements

This news release contains forward-looking information relating to adding to reserves and resource estimates, planned development and exploration activities on the properties in which the Company has interests, and other statements that are not historical facts. Such forward-looking information is subject to important risks, uncertainties and assumptions. The results or events predicated in this forward-looking information may differ materially from actual results or events. As a result, you are cautioned not to place undue reliance on this forward-looking information.

Forward-looking information is based on certain factors and assumptions regarding, among other things, the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products, and other similar matters. While the Company considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

Forward looking-information is subject to certain factors, including risks and uncertainties that could cause actual results to differ materially from what is currently expected. These factors include risks associated with instability of the economic environments in which the Company operates or owns interests, oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources, reliance on key personnel, regulatory risks and delays, including risks relating to the acquisition of necessary licenses and permits, environmental risks and insurance risks.

The estimates of resources in this news release constitute forward-looking information which is subject to certain risks and uncertainties, including those associated with the drilling and completion of future wells, limited available geological data and uncertainties regarding the actual production characteristics of, and recovery efficiencies associated with, the reservoirs, all of which are being assumed. As estimates, there is no guarantee that the estimated reserves or resources will be recovered or produced. Actual reserves and resources may be greater than or less than the estimates provided in this presentation.

You should not place undue importance on forward-looking information and should not rely upon this information as of any other date. While the Company may elect to, the Company is under no obligation and does not undertake to update this information at any particular time, except as required by law.

Resource Definitions

This discussion has been excerpted from Sections 5.2 and 5.3 of the Canadian Oil and Gas Evaluation Handbook, Second Edition, September 1, 2007. The following definitions relate to the subdivisions in the SPE-PRMS resources classification framework and use the primary nomenclature and concepts contained in the 2007 SPE-PRMS, with direct excerpts shown in italics.

Production is the cumulative quantity of petroleum that has been recovered at a given date.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.

Classification of Resources

When evaluating resources, in particular, contingent and prospective resources, the following mutually exclusive categories are recommended:

  • Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term reflects a P90 confidence level.

  • Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term is a measure of central tendency of the uncertainty distribution (most likely/mode, P50/median, or arithmetic average/mean).

  • High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term reflects a P10 confidence level.

Company Gross Contingent Resources are the Company's working interest share of the contingent resources, before deduction of any royalties.

Company Net Contingent Resources are the gross contingent resources of the properties in which the Company has an interest, less all Crown, freehold, and overriding royalties and interests owned by others.

ABN 42 112 256 649

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

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