Country Information
Kurdistan
As a member of a consortium operated by Niko Resources, Groundstar entered into its first Production Sharing Contract ("PSC") with the Kurdistan Regional Government ("KRG" or "Government") for the exploration, development and production of petroleum resources in the 846 square kilometer Qara Dagh block in Sulaymaniyah Governorate of the Federal Region of Kurdistan, Iraq, on May 14, 2008. Groundstar has a 6% net participating interest.
The block lies on trend with existing discoveries, a portion of which covers a large unexplored 65 kilometer long by 6 kilometer wide surface structure with existing oil seeps. Of interest, Qara Dagh translates into Black Mountain.
The consortium operated by Niko has a 60% participating interest that is not subject to further dilution by the KRG. The Government will have a direct 20% interest carried exclusively by the consortium. The remaining 20% was assigned equally to Groundstar's partners, Niko Resources and Vast Exploration on September 22, 2009.
The obligations under the PSC included a onetime signature bonus and capacity building bonus paid to the Government within 30 days from the execution date of the contract. Annual contributions to personnel, training and technological funds established by the Government, as well as community support contributions are to be paid over a period of 15 months to assist with infrastructure projects in the area. The consortium will also be responsible for paying its proportionate share of certain production bonuses in the case of a commercial discovery. The remaining minimum work program obligations represent an exploration commitment which includes the acquisition, processing and interpretation of a minimum of 300 kilometers of 2D seismic data and drilling of one well during the first exploration period.
On January 18, 2010, the Corporation announced that AJM Petroleum Consultants completed an initial resource assessment of Qara Dagh block. AJM has estimated an un-risked best estimate of 2.7 billion barrels of petroleum initially in place as of December 31, 2009. This assessment was prepared by the operator on behalf of the consortium. The consortium, operated by Niko Resources, completed the award of contracts for supply and services required for drilling of the Qara Dagh - 1 well and two potential additional wells. The operator was also engaged in drilling a water well, well site and access road construction for the Qara Dagh - 1 well, which spud on May, 11, 2010.
Figure 1 Figure 1:
Qara Dagh Quickbird Image with Seismic Grid - In June 2009, the consortium completed the acquisition of 355 kilometers of 2D seismic over the surface structure that dominates the Qara Dagh block. Three potential drilling locations have been identified from interpretation of the seismic.
Figure 2 Figure 2:
Qara Dagh Depth Structure Map and Seismic Line QD09-13 -. The Qara Dagh -1 wildcat planned to drill to approximately 4,000 meters and could penetrate up to seven potential reservoirs in the Cretaceous, Jurassic and Triassic in a seismically closed structure of 100 to 140 square kilometers in area. Drilling of the Qara Dagh-1 well reached a total depth of 3,908 meters on May 18, 2011. The well has been log evaluated and a DST evaluation of the prospective zones began on June 7, 2011. Five DSTs were conducted during the evaluation program and no commercial hydrocarbon rates were achieved.
From the well data interpretation, and the significant spike in observed well bore pressures before the drilling stopped, it is believed that the well has potentially entered into the first 10 meters of the next reservoir, the Cretaceous-aged Kometan formation, which is one of the primary target zones previously identified. It is important to note that the Kometan formation is regionally known to be a naturally fractured reservoir that contains significant quantities of oil. Log data and drillstem testing suggest that the well is in a potential oil column through the entire Tanjero-Shiranish interval tested but lacks adequate reservoir for significant flow rates.
The forward plan is to deepen the well to approximately 4,150 meters to reach the Kometan and possibly the Qamchuqa formations.
Africa:
Egypt Exploration Blocks
The Republic of Egypt, approximately 1 million square kilometers in area with a population of about 80 million. The official language is Arabic with English and French being widely understood. Egypt's GNP is derived from agriculture 17%, industry (including oil and gas) 33% and services (including tourism) 50%. Cairo is the administrative capital of Egypt.
Oil was first discovered in 1886 and the country continues to attract local and foreign multinational companies to explore for, develop and produce oil and gas resources. The country currently produces approximately 700,000 barrels of oil per day from proven reserves of 2.7 billion barrels. In excess of 50% of these reserves have been discovered within the complex faulting and associated traps of the Gulf of Suez rift basin system.
Continental rift basins, while being found in many parts of the world are of particular interest in Eastern Africa and the Middle East where they have become highly productive and prospective exploration targets. In addition to significant hydrocarbon accumulations in the Gulf of Suez, rift systems form the geological environment productive in the Muglad Basin in Sudan, and the Marib Basin in Yemen. More recently, international explorers have turned to the Upper Egypt region where a significant trend of rifting, the Nuqra/ Kom Ombo basin system has been defined.
Groundstar has a working interest in two Upper Egypt blocks: the West Kom Ombo block which lies west of the Nile River opposite the cities of Luxor and Aswan and the West Esh El Mellaha block onshore Gulf of Suez west of the city of Hurghada.
West Kom Ombo Block (WKO)
On July 4, 2006, Groundstar Resources entered into a Farm-in agreement with Pan Pacific Petroleum Egypt for the West Kom Ombo block (42,291 square kilometers) in Upper Egypt, one of the largest onshore blocks in the country. Groundstar was the original operator of the block. The Corporation paid 100% of the first US $7 million of exploration expenditure, and paid a signing bonus of US$ 100 thousand to acquire a 60% working interest in the block. The initial phase of two years began on September 17, 2006, and had a gross financial commitment of US$ 3 million. After the gross expenditure of US$ 7 million the Corporation pays 60% of expenditures to retain its 60% working interest. The Corporation has now met its financial obligations.
In a strategic move, the Corporation has entered into an agreement in January 2010 to exchange its 20% working interest in the WEEM Block for an additional 20% working interest in the WKO Block. The agreement is subject to certain adjustments and Egyptian governmental approval.
Figure 3 Figure 3:
West Kom Ombo (WKO) Block – Figure 3 illustrates the location of the WKO block relative to the Centurion/Sea Dragon block immediately to the east and Transglobe's block east of the Nile River. The WKO block originally totaled 42,291 square kilometers (approx. 10.5 million acres). After the mandatory 25% relinquishment of the original area in September 2008, the block area is currently 31,520 square kilometers. Groundstar originally had a 60% working interest. The green lines are the location of the 2D seismic grid acquired by Repsol in 1997 and the grey lines Groundstar's 2008 2D seismic survey. Groundstar re-processed Repsol's legacy seismic grid of approximately 850 kilometers in 2007. The nearest well control is in the Kom Ombo area about 75 kilometers to the east of the WKO block. Repsol drilled several wells there in the 1990s and Sea Dragon Energy with joint operator Centurion Energy, is currently conducting a successful development and production program. The Centurion KomOmbo #4 (Al Baraka #1) well discovered the Lower Cretaceous Al Baraka Field in 2007 recovering 150 barrels/day of light gravity oil (37° API) on test, establishing the presence of an active petroleum system in the area. The Centurion Al Baraka #2 appraisal well discovered a new Lower Cretaceous reservoir which has significantly increased the oil reserves of the field. The fourth well in the field, completed in late 2009, encountered approximately 75 feet of net pay in 2 reservoirs, and preliminary testing indicates the well capable of producing at a maximum rate of 1,300 bopd. On January 13, 2010, Sea Dragon Energy (SDX, TSX Venture) announced that its wholly owned subsidiary, Sea Dragon Energy (Kom Ombo) Ltd. has signed a Farm-Out Agreement with Dana Gas Egypt Ltd. pursuant to which Sea Dragon will acquire a 50% participating interest in the Kom Ombo block. The total consideration paid by Sea Dragon is US $45 million subject to working capital adjustments. As of May 2011, gross production from the Al Baraka Field was 800 bopd.
Groundstar entered the first Exploration phase of three years on September 17, 2008, with a work program commitment to drill 2 exploration wells before September 17, 2011, with a minimum financial commitment of US$ 4 million, all of which has already been spent.
In late January 2009, Groundstar completed a 2D detailed seismic program over five previously identified structures on the WKO block. The contracted CGG-Ardiseis seismic crew acquired 27,999 VPs (700 kilometers). The data quality is significantly better than the legacy seismic previously acquired in the area. Two prospects and thirteen leads were originally confirmed after interpretation of the new seismic. Subsequently, in 2010, one of the leads (Lead A) was raised to prospect status.
Figure 4 Figure 4:
Gustavson Associates Recoverable Resource Estimate for West Kom Ombo - Groundstar contracted Gustavson Associates of Boulder, Colorado to undertake an independent NI51-101 compliant resource assessment of the block. Gustavson re-interpreted the re-processed Repsol seismic data and well results prior to the completion of the resource estimate calculations. It recognized the same five prospects mapped previously by Groundstar on the legacy seismic. The recoverable resources for the prospects were determined from a single Lower Cretaceous sandstone reservoir. As the Lower Cretaceous is interpreted to be a thick sandstone/shale sequence, Gustavson states that multiple reservoir zones are possible as has been reported by the drilling results of the Centurion Al Baraka #2 appraisal well in the Al Baraka Field. In addition, no resources were assigned to the potential deeper structures demonstrated on the Repsol seismic sections.
Figure 5 Figure 5:
West Kom Ombo Summary Map - Prospects A, B and C were confirmed following interpretation of the 2008/09 seismic acquisition. The original prospects D and E mapped on the legacy seismic have been designated leads. Extensive portions of the block lack seismic coverage so the possibility of finding additional prospects and leads is high.
Figure 6 Figure 6:
Top Lower Cretaceous Time Structure Map – Prospect A area with the proposed location for wildcat well WK0-1 on Prospect A1. The proposed location for A1 was on a large three way dip closure bordered to the south by a regional horst block. The trap is dependent upon the bounding fault forming the north side of the horst. Lower Cretaceous Abu Ballas and Six Hills sandstones similar to those containing oil in the Al Baraka Field were the primary objectives. Secondary objectives were sandstones in the Upper Jurassic Six Hills Formation. Mature oil source kitchens are interpreted to be in the Lower Cretaceous and Upper Jurassic transitional marine to lacustrine shales in the deeper troughs bordering the structure. The petroleum system is considered to be an extension of that in the Kom Ombo Basin to the southeast.
Figure 7 Figure 7:
Prospect B on Lower Cretaceous Time Structure Map and Seismic Line GSR08-05- Prospect B has a four-way dip closure of 130 square kilometers in area in two adjacent structures. Fault closure would combine these highs into a single large structure 335 square kilometers in area on the Lower Cretaceous Time Structure Map.
On June 6, 2010, the Corporation entered into a Purchase and Sale Agreement with Aegean Energy Limited, an unrelated third party, to dispose of 7/8ths of its interest (after giving effect to the Asset Exchange Agreement) in the WKO Block for cash consideration of US$5.0 million. Pursuant to the agreement, the Corporation’s remaining 1/8th interest will be carried by Aegean for the first US$30.0 million in expenditures (US$3.0 million net to Groundstar). Aegean is required to drill a minimum of four exploration wells by September 2013. The first exploration phase ends in September 2011 and required Aegean to drill two exploratory wells. Upon completion of a commercial discovery, the Corporation is entitled to a bonus of an additional US$1.0 million. As part of the agreement, Aegean has agreed to provide Groundstar with a US$2.0 million dollar loan that bears interest at LIBOR plus 4% per annum for a term of six months, as well as a US$1.0 million interest free loan for its future activity in WKO. Upon closing of the asset sale, the loan and accrued interest thereon is repayable in full. The agreement is subject to: (a) completion of the asset exchange agreement between the Corporation and Karl Thomson Energy Limited, an unrelated third party; and (b) receiving the appropriate Egyptian governmental authority approvals.
Aegean Energy Egypt Ltd. became operator of the WKO block in October 2010. Subsequently, on January 4, 2011 WKO-1 was spud as the first exploration well on the WKO block. It was located on Prospect A1, a large fault controlled closure defined by seismic data. The well encountered elevated C1-C3 gas readings in the lower Cretaceous sedimentary section which confirmed lateral migration of hydrocarbons from a kitchen area. However, after drilling to 991 meters, the bottom hole sample cuttings were identified to be from granitic basement. As no hydrocarbon bearing reservoirs were encountered, no tests were run. The well was plugged and abandoned.
The drilling rig was moved to a drill site on Prospect B, also a seismically defined structure. WKO-3 was spud on March 7, 2011 as a stratigraphic control point to calibrate the seismic coverage and help define future exploration activities in the block. On April 4, 2011 the well reached basement at 769 meters. The well was plugged and abandoned. The completion of WKO-3 drilling fulfils the contractual obligation of the first extension of the exploration phase on the West Kom Ombo block.
Prior to additional exploration drilling, Aegean Energy plans to conduct an aeromagnetic survey to identify deeper basinal areas on the block which may be followed by seismic acquisition.
West Esh El Mellaha Block (WEEM)
Figure 8 Figure 8:
West Esh El Mellaha (WEEM) Block - Groundstar Resources acquired a 20% working interest in the prospective West Esh El Mellaha (WEEM) block in the southern Gulf of Suez area. Aminex is the operator of the block. The original WEEM block covered 1,328 square kilometers on a western arm of the major northwest trending Gulf of Suez rift system. The sedimentary section is predicted to be in communication with, and consistent with, the Gulf of Suez area, thereby offering access to proven source rock, while the complex structural history of the area indicates the presence of potential traps. Infrastructure essential for production and transportation of oil and gas is mature in the Gulf area, and is expected to readily accommodate production from any new discoveries on WEEM.
Adjacent to WEEM in the southeast, five oil accumulations have been discovered: Rabeh, East Rabeh, Tanan, Tawoos and Wadi El Sahl. Current production, operated by Lukoil, is about 12,000 barrels of oil per day. To the east of WEEM, both on-shore and off-shore, numerous prolific oil accumulations have been discovered in the Gulf of Suez rift basin environment.
The Corporation's minimum financial commitment for this phase was a net expenditure of US$ 3.6 million. The minimum work program for the block was the drilling of 3 exploration wells. The financial and drilling commitments have been met.
In 2008, two wells were drilled by the partners. Malak #1 reached a total depth of 3,694 meters, encountering elevated gas readings, but was subsequently abandoned as a dry hole. NW Tanan #1 was drilled next to a depth of 2,553 meters without encountering reservoir rocks or hydrocarbon shows. It was plugged and abandoned. The total net cost to Groundstar for drilling the two wells was US$ 1.8 million.
The South Malak #1 well, which spud on August 16, 2009 was drilled 1.9 kilometers southeast of Malak #1 and reached a total depth of 3,415 meters in the Basement on October 21, 2009. The reservoir objectives were the Miocene Nukhul sandstone and the Pre-Miocene Matulla and Nubian sandstones. High gas readings were recorded over 290 meters and mud logs indicated oil shows in Eocene dolomite and Cretaceous Matulla sands as well as in Precambrian basement. The Nubian sand was not present. Subsequent testing showed the three potential reservoirs to be too tight to flow satisfactorily. Groundstar then opted out of the well while Aminex continued on to conduct hydraulic fracturing of the formations.
At the end of the Initial Exploration Period (September 2009), the operator released 25% of the concession area in the marginal portion of the block in accordance to the concession agreement. The remaining block area is 996 square kilometers.
On January 25, 2010, the Corporation entered into an Asset Exchange Agreement ("Exchange Agreement"), with Karl Thomson Energy Limited, corporate successor to its partners in Egypt, which provided that the Corporation would assign its 20% working interest in WEEM block in exchange for an additional 20% working interest in WKO block. The agreement contains provisions for monetary adjustments and is subject to Egyptian government approval. Once the transfer of the deeds of assignment are approved, Groundstar will cease to have an interest in the block.
South America
Guyana: Takutu Basin PPL
Figure 9 Figure 9:
Guyana Country Map - On March 11, 2008 Groundstar obtained a Farm-in partner, Canacol Energy Ltd., for the Takutu Basin. The fiscal terms for the Farm-in Agreement obligated the Farmee to pay 100% of all exploration expenses for the first US$ 12 million to earn an undivided 55% working interest in the block. The Corporation completed community consultation and environmental impact management studies and fulfilled its commitment in drilling Takutu Oil & Gas Apoteri K-2 on the Karanambo Prospect. It has also completed construction of the staging area for the Rewa Prospect.
In May 2009, it was announced that Canacol would acquire an additional 35% working interest in the Petroleum Prospecting Licence (PPL) in the Takutu Basin in exchange for a cash payment to Groundstar of US$ 3.45 million. Canacol's net working interest in the PPL increased to 90%; Groundstar's net interest was reduced to 10% which is carried by Canacol to first commercial production. Groundstar was to remain operator of the block through to the completion of the Apoteri K-2 well, after which Canacol has the right to apply to the Guyana Government to become operator for the project.
Under the terms of a new (May 22, 2009) 3 year Petroleum Agreement with the Guyana Geology and Mines Commission the operator is obliged to drill two exploration wells by May 22, 2011. Due to the results of the K-2 well and logistics issues Takutu Oil & Gas (subsidiary of Groundstar Resources) requested the GGMC for an extension for beginning drilling the second well in Q1, 2012.
Figure 10 Figure 10:
Takutu Basin: Groundstar PPL, Seismic Grid, Wells and Prospects - Home Oil and Hunt Oil acquired 2,576 kilometers of high quality 2D seismic in the Guyana portion of the Takutu Basin. Five prospects were originally mapped by Groundstar based on this seismic. They were named Karanambo, Rewa A, B, C and Pirara River. The Apoteri K-2 well was located on the Karanambo structure on the Northern Savannah Arch. Three of the remaining prospects are in the Rewa area near the northeastern margin of the rift basin, and one is on the Northern Savannah Arch to the south of Karanambo-1 and Apoteri K-2.
Figure 11 Figure 11:
Rewa Prospects A, B and C prognosed to drill to total depths of approximately 1,000 to 1,400 meters. Conventional Jurassic sandstone is the primary reservoir objective in normal fault blocks. Secondary fractured reservoir objectives could occur in the Manari Fm. and Apoteri Volcanics in all three prospects. Rewa A and B prospects consist of two separate fault blocks with a combined area of potential structural closure of 225 square kilometers at the Top Apoteri Volcanics. Seismic data suggests that sandstone reservoirs could be present in the Lower Jurassic Manari and Pirara formations above the basalt.
Rewa C is about 28 square kilometers in area at the Top Pirara Fm. with conventional sandstone primary reservoir objectives in the Middle to Upper Jurassic Pirara and Basal Takutu formations. This structure has the thickest interval containing potential reservoir sandstones among the three Rewa prospects.
The Pirara River Prospect is located on the Northern Savannah Arch 12 kilometers south of Apoteri K-2. The primary objective is shallow sandstones in the Takutu and Upper Pirara formations. The three-way dip closure is bordered to the south by a regional fault. The area of closure is 15 square kilometers at the Top Pirara Fm. The Manari-Apoteri section would be a secondary objective.
Drilling results: The Corporation, through its subsidiary, spudded Takutu Oil and Gas et al Apoteri K-2 on December 31, 2010 and announced the rig release on April 30, 2011. The deviated well was located 600 meters from the Karanambo-1 oil discovery made by Home Oil in 1982. The original K-2 wellbore penetrated the Top Apoteri Volcanics 293 meters shallow to prognosis due to crossing a fault that had not been recognized on seismic prior to drilling. The well was sidetracked (K-2 ST1) at 2414 meters to a total measured depth of 2991 meters (2842 meters TVD), and after four drillstem tests was subsequently plugged and abandoned.
Apoteri K-2 penetrated a vertical thickness of 421 meters of Apoteri Volcanics. Common spotty live oil staining and occasional dull yellow fluorescence were observed in cuttings in the Basal Manari shale and Apoteri Volcanics between 2490 and 2900 meters. Also, C1-C5 gas readings were consistently recorded in the Lower Pirara Formation and Manari-Apoteri sections. A significant lost circulation zone was penetrated at 2976 meters MD, and drilling stopped shortly thereafter. Live oil shows and locally elevated C1-C5 gas readings indicated that a substantial part of the Apoteri Volcanics was in a potential oil productive zone except that anticipated fracturing was not developed. Most of the fractures interpreted on the Formation Micro Image log (FMI) had been cemented by calcium carbonate or were induced by drilling.
DST #1 was a misrun after which three successful, barefoot open hole drillstem tests were conducted before the well was abandoned. DST #2 (2445-2571 meters) crossed a zone that had oil shows in the samples and mud but recovered only 46.6 meters of drilling mud from an impermeable Manari shale and Apoteri basalt sequence. DST #3 (2654-2800 meters) was conducted over a section containing elevated C1-C5 gas readings. However, it recovered only 73 meters of drilling mud from a very low permeability basalt interval containing thinly bedded clastics. DST #4 (2897-2991 meters) recovered 2308 meters of formation water containing 84,900 ppm chlorides. The water came from a nearby high permeability aquifer in contact with the lost circulation zone encountered at 2976 meters. Pressure-depth plots indicated that a permeability barrier, likely a fault, exists between the K-1 and K-2 wells.
The disappointing results from Apoteri K-2 has downgraded but not condemned the fracture play in the basin. The Karanambo-1 discovery flowed at a rate of 411 bopd from fractures near the Top Apoteri. The high fluid flow rate in Apoteri K-2 (3875 bwpd) from fractures 400 meters below the Top Apoteri shows that the volcanics still could form a potentially productive oil reservoir elsewhere in the basin.
Currently, Groundstar and its partners are re-evaluating the seismic and well data to determine the location of the second commitment well in the basin.