Houston American Energy Updates Test Results from La. Well

Houston American Energy Corp. announced Friday that Pennington Oil & Gas, LLC, the operator of the Crown Paper #1 well in the Profit Island Field in East Baton Rouge Parish, Louisiana, has successfully carried out a recompletion of the Crown Paper #1 well. Houston American holds a 5.675 percent royalty interest in the well, which interest will be reduced to a 2.838 percent royalty interest after Houston American's receipt of royalties totaling approximately $225,000. Houston American also holds working interests and royalty interest in adjacent acreage to the Profit Island Field.

The Crown Paper #1 well came back on production following the recompletion April 25 and is currently producing in excess of 300 barrels of condensate and 900 mcf of gas per day.

John Terwilliger, Chief Executive Officer of Houston American Energy, stated, "While it is early in its production life for this new interval, I am very pleased with the initial production from the well. As a royalty owner, Houston American is not privy to all of the data on the well and can't speak as to the future cash flows that may be realized from the well. Nonetheless, I view the successful recompletion in the Tuscaloosa Sand as favorable to our Profit Island and North Profit Island Prospects. Houston American will continue to evaluate this area as well as pursue other domestic opportunities."

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Regal Updates on Ukrainian Reserves

Regal Petroleum issued an update Monday on its reserves and resources in its onshore Ukrainian gas and condensate fields.

Regal reported that remaining reserves as of Dec. 31 2012 in the Visean reservoirs of its Mekhediviska-Golotvshinska (MEX-GOL) and Svyrydivske (SV) gas and condensate fields stood at 7.7 million barrels of oil equivalent of proved (1P) reserves, 31.6 MMboe of proved and probable (2P) reserves and 52.6 million barrels of proved, probable and possible (3P) reserves.

Contingent resources at the reservoirs were estimated at between 36.6 MMboe (1C) and 148.8 MMboe (3C).

Regal noted that there has been a "material reduction" in 1P and 2P reserves compared to estimates made in 2010 that showed them to be 40.9 MMboe and 151.3 MMboe respectively. The firm said that these reductions reflect lower expected recovery factors. However, it said that further development of the fields may result in future movement of contingent resources into reserves.

Regal said that independent petroleum consultants ERC Equipoise carried out the assessment for the remaining reserves and contingent resources.

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Petroamerica Updates Testing Results from Colombia Well

Petroamerica Oil Corp. presented preliminary drilling results for its Las Maracas-8 well on the Los Ocarros Block, and provide the results of selective testing for the La Casona-1 well on the El Eden Block, Colombia.

The Las Maracas-8 well was targeting the northern extension of the Las Maracas field and reached its total depth in a record drilling time of 10 days. A petrophysical evaluation of wireline logs from the well indicates more than 56 feet (true vertical depth (TVD)) of net pay, comprising 34 feet (TVD) in the Mirador Formation and 22 feet (TVD) in the middle Gacheta reservoir. The well is currently being cased, and it is expected that the well will be completed as a Mirador producer initially. Following completion, the rig is expected to drill Las Maracas-9 that will target the Gacheta and Une reservoirs.

The Las Maracas Field is currently producing between 8,000 to 9,000 barrels of oil per day (bopd) in total and the permanent production facility is still on schedule for completion by the end of May 2013.

The Company also carried out an extensive testing program of the Une and Gacheta reservoirs in its La Casona-1 well using a workover rig.

The Une Formation in La Casona-1 flow tested at an average rate of 1,700 bopd and 6 million cubic feed per day (MMcf/d) of gas over a 56-hour period. The well produced under natural flow conditions and the quality of the crude oil produced was 35 degree API. The measured watercut at the end of the test was 1 percent.

A number of basal Gacheta sands, not previously described in net pay numbers that were announced in the November 13, 2012 press release, were also tested and produced 105 bopd of light 24 degree API oil and 0.5 MMcf/d of gas. The watercut at the end of the test was 2 percent. A middle Gacheta sand was also tested separately yielding no flow to surface. It is speculated that this last test was dry due to either formation damage, or the well required more clean-up time to flow naturally.

The Mirador Formation, which had good oil shows and potential hydrocarbon pay from logs, could not be tested in this well due to a poor cement bond. It is expected that the Mirador, Gacheta and Une reservoirs will be further evaluated with a follow-up well, La Casona-2, to be drilled later this year.

The operator of the block is currently procuring production facilities that include natural gas compression equipment and plans to use the produced gas as a power source at the Las Maracas and Kona production facilities. Production from the La Casona discovery is expected to commence sometime during the third quarter of 2013.

Petroamerica holds a 50 percent participating interest in the Los Ocarros Block where the Las Maracas field is situated, and a 40 percent participating interest in the El Eden Block, 15 percent of which is still pending approval by the Colombian National Hydrocarbon Agency (ANH), where the La Casona discovery is located.

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Regal Updates on Ukrainian Reserves

Regal Petroleum issued an update Monday on its reserves and resources in its onshore Ukrainian gas and condensate fields.

Regal reported that remaining reserves as of Dec. 31 2012 in the Visean reservoirs of its Mekhediviska-Golotvshinska (MEX-GOL) and Svyrydivske (SV) gas and condensate fields stood at 7.7 million barrels of oil equivalent of proved (1P) reserves, 31.6 MMboe of proved and probable (2P) reserves and 52.6 million barrels of proved, probable and possible (3P) reserves.

Contingent resources at the reservoirs were estimated at between 36.6 MMboe (1C) and 148.8 MMboe (3C).

Regal noted that there has been a "material reduction" in 1P and 2P reserves compared to estimates made in 2010 that showed them to be 40.9 MMboe and 151.3 MMboe respectively. The firm said that these reductions reflect lower expected recovery factors. However, it said that further development of the fields may result in future movement of contingent resources into reserves.

Regal said that independent petroleum consultants ERC Equipoise carried out the assessment for the remaining reserves and contingent resources.

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Dragon Oil Updates Ops at Lam Well

Dragon Oil plc, an international oil and gas exploration, development and production company, published a quarterly update on the wells completed and tested in the first quarter of 2013.

The Dzheitune (Lam) 28/178 well, in the Cheleken Contract Area offshore Turkmenistan, was completed as a single producer to a depth of 6,594 feet (2,010 meters) and tested in February 2013. The well tested at an initial production rate of 1,653 barrels of oil per day (bopd). This well is currently stabilized and producing at a rate of 2,065 bopd. The jackup rig is currently drilling the Dzheitune (Lam) 21/180 and 21/181 development wells in a batch drilling mode.

The Dzheitune (Lam) 28/179 well was also completed as a single producer in March 2013. The depth of the well was 6,184 feet (1,885 meters) and the well tested for initial production of 1,975 bopd. This well is presently producing at a rate of 2,218 bopd. The land rig is currently drilling the Dzheitune (Lam) 28/182 well.

The average field production for 1Q 2013 was 71,800 bopd (1Q 2012: 70,600 bopd). The average production for March 2013 was 74,000 (March 2012: 72,000 bopd) with the quarter's exit rate at approximately 76,400 bopd.

We reiterate our guidance for the growth rate for the full year 2013 to be at the lower end of the medium-term growth rate of 10 to 15 percent.

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Dragon Oil Updates Ops at Lam Well

Dragon Oil plc, an international oil and gas exploration, development and production company, published a quarterly update on the wells completed and tested in the first quarter of 2013.

The Dzheitune (Lam) 28/178 well, in the Cheleken Contract Area offshore Turkmenistan, was completed as a single producer to a depth of 6,594 feet (2,010 meters) and tested in February 2013. The well tested at an initial production rate of 1,653 barrels of oil per day (bopd). This well is currently stabilized and producing at a rate of 2,065 bopd. The jackup rig is currently drilling the Dzheitune (Lam) 21/180 and 21/181 development wells in a batch drilling mode.

The Dzheitune (Lam) 28/179 well was also completed as a single producer in March 2013. The depth of the well was 6,184 feet (1,885 meters) and the well tested for initial production of 1,975 bopd. This well is presently producing at a rate of 2,218 bopd. The land rig is currently drilling the Dzheitune (Lam) 28/182 well.

The average field production for 1Q 2013 was 71,800 bopd (1Q 2012: 70,600 bopd). The average production for March 2013 was 74,000 (March 2012: 72,000 bopd) with the quarter's exit rate at approximately 76,400 bopd.

We reiterate our guidance for the growth rate for the full year 2013 to be at the lower end of the medium-term growth rate of 10 to 15 percent.

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Sefton Updates Tapia Canyon Activity in California

Sefton Resources announced an update on the permitting and drilling of the Hartje replacement water disposal well, oil production from California and the thermal stimulation report of the Tapia Canyon oil field.

All permits are now in place for the drilling of the new water disposal well Hartje #21 and a rig has been located that is available in March 2013.Preliminary oil production data (tank readings, before estimated 4 percent shrinkage) for California has been compiled for the month of January 2013 with 3,507 barrels of oil compared to 4,124 barrels actually produced for the month of December 2012. Production was restricted during January 2013 by Californian State mandated tank testing and repairs. The new Yule lease wells continue to make progress after acidization and steaming.Dr. Farouq Ali believes that work on the history match stage of the thermal simulation study will be completed soon. He has advised that he intends to complete this part of the study by the end of February 2013 and by that time expects to have begun the cyclical steaming matches and various steamflood scenarios.

Jim Ellerton, Chairman of the Board said:

"I am pleased to report that the new water disposal well at Tapia is now fully permitted. Water disposal has been the critical limiting factor in optimizing production at Tapia and the Company can now look to the benefits that upgraded water disposal facilities coupled with the progress that has been witnessed following the acidization and cyclic steaming of the Yule wells.

"Further progress has been made towards the completion of the thermal simulation study on Tapia which will allow the value of the Enhanced Oil Recovery (EOR) project at Sefton's 100 percent-owned Tapia Canyon oil field to be maximized in negotiations with third parties to scale up the size of this project to its ultimate potential."

The Company has completed the permitting for the drilling of the new water disposal well Hartje #21. A rig has been located that is available in March 2013 and negotiations on the drilling contract are proceeding. The drilling of this water disposal well will resolve the most critical oil production limiting factor at Tapia.

Preliminary oil production data (tank data) has been compiled for the month of January 2013. After a 4 percent shrinkage number is applied, tank data indicates an estimate of 3,367 barrels of oil produced or approximately 109 barrels of oil per day (bopd) compared with a final production figure of 133 bopd in December 2012. Production was restricted during January 2013 by tank testing and repairs that were required by new State of California regulations for operators with inspection overseen by the Californian Division of Oil, Gas & Geothermal Resources ("DOGGR").

The regulations required that tanks be emptied of liquids to conduct wall thickness measurements which have disrupted oil production during this process, as wells have been shut in for partial or complete day cycles. Tanks on the Hartje, Lackie/Snow, Yule and Eureka facilities were tested in January and this work has continued into the month of February with 3 tanks remaining to be tested and repaired.

The steam generator is now injecting steam into the wells on the Snow lease. Snow #3 well has just returned to production after steaming and although still producing at a 98 percent water cut due to steam injection it is encouraging that post steaming the well is averaging 200 barrels of gross fluid (water and oil) per day compared with 33 barrels of total gross fluid per day prior to steaming.

Dr. Farouq Ali believes that he will soon complete the history match stage of the thermal simulation study. The history match involves fine tuning of the model to ensure that the model can actively reflect the historical performance of the field since oil production began in the 1950's. Dr. Ali has advised that he intends to complete this part of the study by the end of February 2013 and by that time expects to have begun the cyclical steaming matches and various steamflood scenarios.

The thermal simulation study serves to optimize production and reserve development at Tapia Canyon. From the very beginning, the Board has been determined to get the best possible thermal stimulation report prepared by acknowledged experts in order that the value of Enhanced Oil Recovery (EOR) project at Tapia Canyon can be maximized in negotiations with third parties concerning the full development of this oil field.

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Circle Oil Updates Production Activities in Egypt

Circle Oil Plc announced the following update regarding the Al Amir SE field ("AASE") and the Geyad field.

Infill production well AASE -14X, located centrally in the field midway between AASE-1X ST1 and AASE-12X ST1 was spud Nov. 26, 2012. The well was planned as a Shagar and Rahmi sand producer and was sidetracked for geological reasons Jan. 4 as AASE-14X ST1. The well has encountered 20 feet measured depth (MD) of gross Shagar sand (9,610-9,630 feet MD) with 16 feet MD net pay, plus 15 feet MD of gross Rahmi sand (9,680-9,695 feet MD) with 13 feet MD net pay, with a total depth of 10,000 feet MD. The well is now planned to be completed as a producer and an update will issue once flow testing is completed.

Production from the AASE and Geyad fields averaged 9,091 barrels of oil per day (bopd) (gross) through January 2013. Cumulative production from the NW Gemsa Concession has now exceeded 10.4 million barrels of 42 degree API Crude oil.

The 12 inch gas pipeline has now been tied in and gas production started up Feb. 12. The initial flow rate at start-up was 8 million square cubic feet per day (MMscf/d), or 1,456 barrels of oil equivalent per day (boepd), and is currently 9 MMscf/d (1,638 boepd). The gas is rich in extractable liquids that will add significantly to the income stream for Circle. Gas processing is expected to provide an additional 140 - 150 bocd and 35 tonnes (c. 400 boepd) of LNG per day.

Work on finalizing the development and day to day operations of the AASE and Geyad fields will continue through 2013. The 2013 work program includes the drilling of 4 further wells (1 producer and 3 injectors) in the first half of the year.

The NW Gemsa Concession, containing the Al Amir and Geyad Development Leases, covering an area of over 100 square miles (260 square kilometers), lies about 186 miles (300 kilometers) southeast of Cairo in a partially unexplored area of the Gulf of Suez Basin.

The concession agreement includes the right of conversion to a production license of 20 years, plus extensions, in the event of commercial discoveries. The NW Gemsa Concession partners include: Vegas Oil and Gas (50% interest and operator); Circle Oil Plc (40% interest) and Sea Dragon Energy (10% interest).

Prof Chris Green, CEO, said:

"Circle is very pleased that the AASE-14X ST1 well has encountered pay intervals as prognosed in the Shagar and Rahmi sands and will be completed as a producer to complement the production levels from the AASE field.

The start up of gas flow through the 12" pipeline from our Geyad and AASE fields is another significant step forward as this production is expected to add approximately 2,000 boepd to the daily gross production."

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PetroNova Updates Llanos Basin Drilling Program

PetroNova on Friday provided an update on its Guasco-1 exploratory well located on the CPO-13 Block, in which PetroNova has 20 percent working interest, in Colombia's Llanos Basin.

The Guasco-1 exploration well was spud on Jan. 8, 2013 and reached a total depth of 3,114 feet on Jan. 15, 2013 . The well found poor sand development in the Upper Carbonera Basal section, which was the primary target; however, mud log and petrophysical interpretation indicated a potential prospective zone in the C5 sands. The 2,711 to 2,717 foot interval was perforated and tested, and yielded 100 per cent basic sediment and water. The operator is presently abandoning the well.

PetroNova will continue its drilling campaign and plans to move the rig to the Cayabana prospect in CPO-07.

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ABS Updates Dynamic Positioning Requirements

ABS, a provider of classification services to the global offshore industry, has released the ABS Guide for Dynamic Positioning Systems as a significant update to present classification requirements to reflect industry advancements in the use of dynamic positioning (DP) systems.

"The use of DP systems has been expanded not only in terms of the number of vessels outfitted with the systems, but also in the increasing advancement of DP technologies," said Vice President, Energy Project Development, Ken Richardson, noting that the vast majority of newbuild floating mobile offshore drilling units will have DP capability.

"DP reliability is particularly important in frontier areas where deepwater drilling is reaching greater depths, and in challenging harsh-weather environments around the world," Richardson explains. "The new Guide provides standards for enhanced notations to guide clients in selecting the level of compliance for a vessel’s DP capability, which broadens the notation choices, increasing the likelihood of getting a unit outfitted with the most appropriate system for each application."

The new Enhanced System (EHS) notation encourages robust designs of DP systems by providing optional requirements. The multiple levels of EHS notation – for power, control and fire protection – provide owners with the flexibility to tailor the notation to the most important components of the system for the unit’s intended operations.

Because these newbuilds will work around the globe, the ABS Guide for Dynamic Positioning Systems offers an optional notation for Station-Keeping Performance (SKP). The notation allows owners to select equipment based on North Sea conditions or to select environmental criteria specific to the intended areas of operation.

The DP Guide also includes detailed procedures for assessing available thrust, taking into account thruster interactions (thruster-thruster, thruster-hull, thruster-current), which is especially useful in the early stages of design.

In developing the new ABS Guide for Dynamic Positioning Systems, ABS drew, not only on its years of related experience with DP installations, but also on expertise from equipment manufacturers, owners, operators and industry experts. Part of that process included a workshop in Houston where more than 40 experts participated in a discussion about DP systems and what the industry needs. The results of this event steered the development efforts that produced the recently released Guide.

"This truly collaborative approach to Guide development allows ABS to work with industry to provide guidance that facilitates continued safe operations as the industry’s needs evolve,” says ABS Vice President for Offshore Technology Bret Montaruli. "We understand that DP system reliability is vital to operational safety. And we developed the new Guide to address the diverse and growing needs of the industry with respect to DP systems."

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