Baraka commenced a Joint Venture with Canadian based PetroFrontier Corp.(The Operator) in April 2010, where Baraka retained an undivided 25% working interest in both EP-127 and EP-128(approx 2 million net acres) plus an undivided 75% working interest in approximately 75km² around the Elkedra-7 well on EP 128, where previous drilling has indicated oil shows. In fact there have been at least 7 wells drilled on Baraka's permits of which the cores have shown either Bitumen and/or Bitumen Bleed intervals, heavy oil staining and/or oil saturated intervals.
In June 2012, Statoil ASA of Norway (13th largest Oil & Gas Company in the world) subsequently farmed into PetroFrontiers tenements, which includes Baraka's EP-127 and EP-128. Statoil will have the option to earn up to 65% of PetroFrontiers interests in the Southern Georgina Basin in exchange for exploration program related payments and carried costs of up to US$210 million over three phases. The farm-in by Statoil implies a value of approx $26/acre.
In November 2012, Central Petroleum announced that Global energy giant Total (5th largest Oil company in the world) farmed into approx 6 million acres within their Southern Georgina Basin acreage for exploration and development funding of approx US$190 million over three stages. Baraka is now surrounded by Global leaders in exploration and development which not only puts Baraka in an enviable position, it adds tremendous credibility and confidence to the basin. Total's farm-in implies a value of approx $37/acre, this is a substantial increase in value from Statoil's Southern Georgina Basin farm-in of approx $26/acre only 5mths prior, by implication this increases the value of Baraka's land holding. As at November 2012 Baraka's market capitalization of approx AU$23million is significantly undervaluing Baraka based on the implied value of Total's Farm-in, $37/acre would value Baraka's 2 million net acres at approx $74 million. Future success in exploration and or production will further increase the per acre valuation as it has done in the "Bakken", USA/Canada
The Georgina basin is a region of proven oil potential and represents one of the few remaining virtually unexplored, hydrocarbon, and onshore sedimentary basins in the world. "The southern Georgina Basin, onshore Australia, hosts high quality source beds and potential conventional and unconventional reservoir rocks. We believe that this basin is one of the most prospective onshore basins in Australia with potential for both very large conventional and unconventional oil and gas deposits. The Basin covers more than 100,000 square kilometers (24.7 million acres) in the NT and western part of Queensland. Baraka's two Exploration Permits are situated over what is believed to be a prospective part of the basin" (Source: Ryder Scott). *The Ryder Scott Report can be found on the Reports and Presentations page of this website.
It is currently a sparsely explored green field area which makes up part of the Centralian Superbasin, comprising the Amadeus, Georgina and Wiso sub-basins. During the Cambrian era, the Central Australian plate was on the subtropical waters on the fringes of the Rodinia supercontinent. In this period, the organic-rich Arthur Creek black marine shales were deposited, particularly in the Dulcie and Toko troughs. Similar Cambrian marine shales are the source rocks in the extremely productive fields of East Siberia, Oman and the Tarim Basin in China. Above the Arthur Creek shales are the Thorntonia and Hagen Formations, both of which have been shown by previous drilling to show good reservoir properties and anhydrite seals. The Georgina Basin therefore has all the attributes of a productive hydrocarbon province. This prospectivity has been enhanced by oil shows in a number of wells, and gas flows to surface in the Ethabuka-1 and the Discovery Creek water bore.
Previous test wells drilled in the Georgina Basin have demonstrated oil shows and good quality source rocks, seals and reservoirs with target horizons ranging from 300 metres to 1000 metres. A total of twenty nine wells had been drilled, with the most recent eight wells being drilled in 1991, all of which had oil shows but were abandoned. However, advancements in drilling technologies, namely the use of horizontal and multi stage fraccing technology has made basins such as South Georgina a valuable exploration prospect.
HISTORICAL EXPLORATION TEST
Early exploration in the Georgina Basin consisted of stratigraphic holes or wells whose location was based on surface geological mapping. This included a number of wells drilled in the 1950s and 1960s, culminating in the Ethabuka-1 well in Queensland which recovered gas at 6,000 m3 per day (240,000 cfd) on test. Subsequent drilling in the early 1980s was restricted to the stratigraphic drilling program undertaken by the Northern territory Geological Survey ("NTGS"). In the late 1980's to early 1990s, Pacific Oil and Gas explored areas in the Dulcie and Toko Synclines with the first serious attempt to acquire a regional seismic grid and drill wells based on its results. Some 750 kilometres seismic data were collected and 10 wells were drilled. The seismic lines were 5 to 30 kilometres apart, however most wells, recorded poor to moderate oil shows.
RECENT EXPLORATION PROGRAM
The first drilling campaign carried out by Baraka and its Joint Venture Partner(The Operator), consisted of three horizontal wells that will require multi-stage fracturing & completion, one on Baraka's EP-127(MacIntyre-2) and two on the neighbouring tenements EP-103(Baldwin-2) and EP-104(Owen-3H) both owned by Baraka's joint venture partner. This Horizontal and multi-stage fraccing technology is a highly successful method widely used in North America to unlock unconventional reservoirs in oil shale zones in formations such as the Bakken formation. Baraka's management believes this was the first time such Technology had been utilized on Oil Shale in Australia. The use of Horizontal and Multi-Stage Fraccing stimulation technology enhances the possibility of a discovery by opening up hundreds of metres of potential pay zone.
October 2011, "MacIntyre-2" was drilled as a high angle pilot hole through the Basal Arthur Creek "Hot Shale" formation and into the Thorntonian carbonate formation. The inclined pilot hole well had been drilled to a measured depth ("MD") of 930 metres. Elevated hydrocarbon shows(C1 through C5) were recorded throughout the entire Basal Arthur Creek "Hot Shale" formation with sustained and high gas peak levels generally two to three times greater than those seen in the vertical pilot hole at Baldwin-2Hst1. In addition to the gas readings, of which some samples were effervescing, there was some evidence of oil on the samples. The logging results for MacIntyre-2 were very positive showing approximately 22 metres of true vertical depth ("TVD") pay with porosities varying between 5 - 11%. Studies completed by two independent petrophysical companies indicated that the Arthur Creek "Hot Shale" zone in MacIntyre-2 may be oil bearing, although natural gas is present as well. Definitive results will be confirmed once the frac and flow testing is completed.
June 2012, Drilling of the horizontal section was re-commenced after the wet season subsided. MacIntyre-2H reached a total measured depth of 1,916 metres and stayed within the primary target zone, the Lower Arthur Creek "Hot Shale" Formation, for approximately 1,080 metres, recording positive hydrocarbon indications along the entire length of the horizontal section. A multistage open-hole completion string was placed in the well in preparation for a completion program.
October 2012, A successful hydraulic stimulation was performed on the MacIntyre-2H well over nine open-hole stages. However, after recovering approximately one-third of the hydraulic stimulation fluid, traces of biogenic hydrogen sulfide gas, produced from naturally occurring organisms in the completion fluid, were detected and the well had to be suspended. The Operator is actively sourcing the specialized equipment to allow flow testing to resume. This is likely to commence in 2013.
Baldwin-2Hst1(EP-103 : NOT Baraka's tenement)
August 2011, "Baldwin-2 Hst1" well reached a total measured depth ("MD") of 1,948 metres and remained within the main target zone in the Lower Arthur Creek "Hot Shale" for 875 metres while directionally drilling up a regional dip of 1.7 degrees. Positive hydrocarbon indications were recorded along the entire length of the horizontal section, with elevated gas readings and evidence of heavier hydrocarbons present. Total gas recorded in Baldwin-2Hst1 averaged 240 units over the entire horizontal section, commonly peaking above 1,000 units with maximum recorded values over 2,500 units. The gas recorded contained heavier hydrocarbon fractions up to pentane ("C5") over much of the horizontal section. Conventional gas ratio analysis indicates very wet gas to oil for the most of the well with occasional definite oil signatures in places. However, this interpretation may be biased to gas due to the nature of the reservoir being intersected. A multistage open-hole completion string was placed in the well in preparation for a completion program.
October 2012, During the hydraulic stimulation program of the Baldwin-2Hst1 well, a shallow casing failure occurred and as a result, The Operator was unable to complete the program. As expected, the multiple casing design protected the shallow aquifers. The Operator plans to carry out remedial work to repair this well so that the planned hydraulic stimulation program can be completed in 2013.
Owen-3(EP-104 : NOT Baraka's tenement)
August 2012, The vertical section of the "Owen-3" horizontal well was drilled to a measured depth of 1,180 metres. A total 32.5 metres of core was cut and retrieved from the Lower Arthur Creek "Hot Shale" and Thorntonia Carbonate formations. The initial assessment of the cores were very encouraging, seeping oil upon retrieval and having extensive florescence throughout. The well was also wire line logged with equally encouraging results indicating over 25 metres total vertical depth ("TVD") of hydrocarbon bearing formation. Total measured depth ("MD") of the Owen-3H well was 2,153 metres, of which the horizontal section was 966 metres targeting the Lower Arthur Creek "Hot Shale" and Thorntonia Carbonate formations. During the drilling of the horizontal section, numerous positive hydrocarbon indicators were observed:
• Oil staining
• Milky yellow fluorescing cut
• Strong gas recordings of C1 to C5
• Petroliferous odour
• Oil spots in the mud at the shaker
A multistage open-hole completion string was placed in the well in preparation for a completion program.
October 2012, A successful hydraulic stimulation was performed on the Owen-3H well over ten open-hole stages. Low fluid injection pressures and high injection rates evident during the stimulation were very encouraging. Log data and core samples had been obtained and appeared positive, confirming the existence of oil in the Lower Arthur Creek and Thorntonia Carbonate Formations. Like the MacIntyre-2H well, Owen-3H encountered nuisance levels of hydrogen sulphide in the initial flow back of the stimulation fluid. Hydrogen sulphide resistant testing equipment, along with a high capacity jet pump and all necessary surface tankage and piping were installed at the Owen-3H well so the cleanup and production testing could be conducted.
The Extended flow-test of the Owen-3H well will take up to 6 weeks depending on weather, equipment reliability and the nature of the recovered fluids. Results are expected some time prior to the end of the year(2012). These early stage results are encouraging and the flow-testing of the well are eagerly anticipated by all companies in the basin.
This data from all three wells will be used to guide the 2013 capital program as it supports the potential for oil recovery in the Southern Georgina Basins unconventional acreage.
SOURCE AND MATURATION
The main source rock interval in the Georgina Basin is the hot shale at the base of the Arthur Creek Formation of Middle Cambrian age. This interval can be mapped throughout the southern Georgina Basin (Ambrose et al 2001). The richest section of this shale is up to 25 metres thick, and has been described as "finely laminated to massive anoxic, carbonaceous, partly dolomitic shale" (Ambrose, 2006). Total organic carbon levels measured in the shale commonly range from 0.5% to 10% and up to 16% (Ambrose et al 2001). The Hagan Member of the Arrinthrunga Formation recorded good oil shows in a number of wells which are believed to have been sourced from intraformational shales (Randall-1, Phillip-2, Elkedra-7 and Todd-1) (Ambrose 2001). TOC's have been measured at up to 4% in Macintyre-1 and Baldwin-1 and up to 7.9% in Elkedra-1. There are a number of seals in the sequence, some regional in nature and others semi-regional or local. The best regional seal is the basal portion of the Arthur Creek Formation described in the previous section. Much of the lower part of the same formation also has good sealing qualities. There are a number of semi-regional seals within the upper section of the Arthur Creek Formation as demonstrated on the log of the MacIntyre-1 well. They appear to represent a number of upward shoaling sequences with the seal at the base, followed by gradually coarser grained sequences, culminating in fair to good reservoir facies at the top of the sequence. There are also a number of anhydrite sequences both within the Arthur Creek Formation and the overlying Hagen Member of the Arrinthrunga Formation. These would represent excellent seals, although their lateral extent is not well known.
The main reservoir target recognised to date is the Thorntonia Limestone of Middle Cambrian age. This unit flowed 500 barrels of water per day (BWPD) from a test in Ross-1 and a drill stem test (DST) in MacIntyre-1 produced 338 metres of water in the pipe. There is not enough information from wells to enable reservoir trends to be established, however it appears that improved permeabilities occur in areas where the Thorntonia limestone is fractured and vuggy and this probably relates at least in part to effects of karstification (Ambrose et al, 2001). The upper portion of the Arthur Creek Formation is dominated by a number of shoaling sequences with reservoir quality rock at the top. In MacIntyre-1, the top of one of these sequences had measured permeabilities of 1.2 Darcies. Dolomitic sandstone seen in Owen-2 exhibited core porosities of 10-15% and permeabilities of 15-95 mD. The Hagen Member of the Arrinthrunga Formation contains dolostones which exhibit vuggy dissolution porosity in some wells. A flow of 300 BWPD was achieved from Randall-1 at this level. There are also reservoirs in the Kelly Creek Formation of Early Ordovician age. This formation flowed gas at about 240,000 cfd from Ethabuka-1. Much further work on this aspect is required before reservoir trends could be confidently predicted.