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The transactions and new licence awards completed to date in Turkey provide exposure to both natural gas and oil opportunities in the country. The extent of Valeura’s pro forma land holdings in the Thrace Basin in northwest Turkey and the Anatolian Basin in southeast Turkey, post closing of the TBNG Acquisition and West Thrace Deep Rights Sale Transactions, is set forth in the table below.
Land Position in Turkey Post Closing of Transactions
The map below shows the Thrace and Anatolian Basins and the Turkish Petroleum Districts (prior to the New Petroleum Law of June 30, 2013).
More than 99% of Valeura's production in Turkey is natural gas produced in the Thrace Basin, which is located in an area west of Istanbul and extending to the borders of Greece and Bulgaria. The map below depicts Valeura’s assets in the Thrace Basin as at November 1, 2016.
Thrace Basin Transactions & Land Position (1) (2)
TBNG JV Producing Assets
The TBNG JV lands (Valeura 40%) acquired in in 2011 are located in the Thrace Basin and initially included four production leases and 10 exploration licences, of which two licences were entirely on land, three licences had a portion in the shallow waters of the Sea of Marmara (up to 200 metre water depth), and five licences were in deeper water (200 to 1,200 metre water depth). The five deep offshore licences were subsequently relinquished in 2011.
One onshore exploration licence (3734) also expired in 2012, after the carve-out of a new production lease, and the relinquished lands were subsequently re-acquired (5151) through a successful application process in 2013.
In the fourth quarter of 2014, the TBNG JV was awarded four new production leases (F18-c4-2, F18-c3-1, F19-d4-1 and F19-d4-2) over part of two existing exploration licences.
In 2015, the GDPA approved an application by the TBNG JV to relinquish expiring exploration licence 3858 and to convert exploration licence 5151 to the new licencing terms under the New Petroleum Law. As a result, the TBNG JV was awarded two new exploration licences (F17-c2, c3 and F18-d1, d2, d4) to replace licence 5151 with an aggregate area of 160,468 gross acres (64,187 net acres). The new licences also encompass part of the expired licence 3858. The TBNG JV made application to the GDPA to post the residual area of expired licence 3858 and submitted a bid for a new exploration licence (F18-d3) in September 2015. This bid remain under review by the GDPA.
The initial five-year term of the newly converted exploration licences F17-c2, c3 and F18-d1, d2, d4 has been extended by more than two years to June 27, 2020. During the initial term, the TBNG JV will be required to complete 100 square kilometres of 3D seismic and drill nine wells with a depth range of 850 to 2,000 metres. The total assigned value of this program is US$15.6 million (gross) and an associated 2% bond has been submitted to the GDPA.
During the course of 2015, the TBNG JV was awarded an additional three production leases (G18-b1-1, G18-b2-1 and G19-a1-1) over part of expired exploration licences 3913 and 3934. Applications to the GDPA for two new production leases (F19-d3-1 and F19-c3-1) over part of expired licences 3934 and 4126 remain under review by the GDPA.
Natural gas is currently produced from both conventional and unconventional (tight gas) sandstone reservoirs in onshore leases and licences on the TBNG JV lands. Gas sales from these lands in Q3 2016 averaged 5.9 MMcf/d (gross) or 2.3 MMcf/d (net).
Average realized prices for Valeura’s gas sales from the TBNG JV lands were $9.49 per Mcf in Q3 2016.
In Q3 2016, approximately 65% of the natural gas produced from the TBNG JV lands was conventional shallow gas produced from approximately 65 wells. Shallow gas is produced from Tertiary-aged stacked sands in the Danismen and Osmancik formations at relatively shallow depths of 500 to 1,500 metres. The gas, which is composed primarily of methane, is gathered, dehydrated and compressed in owned facilities and distributed on an owned sales line network directly to more than 55 light industry customers. TransAtlantic manages the marketing arrangements on behalf of the parties under the joint venture operating agreement.
The TBNG JV has had an active program to exploit the shallow gas resource potential on its lands, including well workovers, 3D seismic and new drilling. In summary, the following programs were completed:
2012: 32 well workovers and nine new shallow exploration and development drill wells (gross);
2013: 14 well workovers, 232 square kilometres of 3D seismic in the Osmanli area and one new shallow gas development drill well (gross);
2014: 21 well workovers, two well re-entry fracs in the Osmancik formation and six new exploration and development vertical wells (including one sidetrack) (gross) drilled on new Osmanli area 3D seismic; and
2015: one development vertical drill well (gross) drilled as an appraisal well in the Osmanli area and nine well workovers.
Opportunities exist to further exploit the shallow gas resource potential through exploration and development drilling, well workovers, and additional wellhead compression to mitigate natural declines.
In particular, new 3D seismic has assisted in identifying new gas exploration play types and subsequent drilling in the second half of 2014 and early 2015 resulted in a significant boost to shallow gas volumes at the time. When the TBNG JV assets were acquired, approximately 3,500 kilometres of legacy 2D seismic was available on the onshore lands in the Thrace Basin but no 3D seismic had been shot. The initial acquisition of 413 square kilometres of new 3D seismic in the Tekirdag and Hayrabolu areas was completed in mid-October 2011 and positioned a ramp-up of deeper, tight gas drilling and selected shallow gas drilling in the second quarter of 2012. In the third and fourth quarters of 2013, an additional 232 square kilometers of 3D seismic was acquired in the Osmanli area and merged with the Tekirdag area 3D seismic to provide coverage over a contiguous area of more than 400 square kilometres.
The new Osmanli 3D seismic identified a number of drilling opportunities for both conventional shallow gas and deeper unconventional tight gas. In the second half of 2014 and early 2015, the Company completed an initial program of seven (gross) conventional gas exploration and development wells in the Osmanli area. All seven wells were cased, of which six are producing.
It is expected that this new merged Osmanli and Tekirdag 3D seismic will provide additional drilling opportunities in future years, targeting both conventional shallow gas and deeper unconventional tight gas.
Valeura acquired its position in the Thrace Basin with the expectation that in addition to further potential in the well-established shallow gas operation there was significant upside potential associated with applying modern multi-stage frac completion technology to exploit deeper unconventional tight gas sands in the Mezardere, Teslimkoy, and Kesan formations in structures that underlie the shallow gas reservoirs. The tight gas formations had seen minimal development in the past. Producing analogies in the Thrace Basin and well results from a small number of deeper wells drilled in the past on the TBNG JV lands indicated the presence of relatively low porosity (6 to 15%), stacked sandstone reservoirs in these formations that tested gas, but these tight gas formations were generally not producible at commercial rates in the absence of fracture stimulation.
There are many other analogies of tight gas reservoirs around the world in similar basins that have benefited from the application of modern drilling and well stimulation technologies and robust capital investment. In parts of the Thrace Basin, there are up to 5,000 metres of sediments with a number of tight gas targets that are expected to benefit from multi-stage fracs in vertical wells, given the relatively large gross thickness of the target interval, or in horizontal wells in selected horizons as geological understanding and frac experience grow.
Unlocking the potential in the deeper unconventional tight gas play in the Thrace Basin has been a priority for the Company since mid-2011. The TBNG JV has carried out an extensive proof-of-concept program since that time to de-risk the normally pressured tight gas play on the southern and western rim of the basin. In summary, the following programs were completed to exploit the normally pressured tight gas in the Osmancik, Mezardere, Teslimkoy and Kesan formations:
2012; 11 vertical exploration and development drill wells (gross), of which was drilled to 3,755 metres;
2013: three vertical exploration and development drill wells (gross), of which the deepest was drilled to 4,054 metres, and three horizontal development wells (gross);
2014: three horizontal development wells (gross); and
2011-2014: 73 fracked wells (gross) (55 well re-entry fracs in vertical wells, 12 fracs on new deep vertical wells and six multi-stage fracs in six new horizontal wells). This program included five well re-entry in lower porosity intervals in Osmancik formation.
The Company's conventional shallow gas (red) and unconventional tight gas (green) drilling program in 2012 to 2016 period on the TBNG JV lands is illustrated in the figure and table below.
TBNG JV New Drill Spuds in 2012 – 2016 YTD
On October 13, 2016, Valeura announced the TBNG Acquisition and West Thrace Deep Rights Sale which increase Valeura's interest in the TBNG JV to 81.5% in the shallow rights and 31.5% in deep rights in the West Thrace lands and 81.5% in all formations in other TBNG JV lands. Valeura also becomes operator of the TBNG JV. This consolidation of the TBNG JV under Valeura operatorship offers opportunities to ramp-up the conventional shallow gas exploration and development program and the tight gas program.
Banarli Exploration Licences
In April 2013, Valeura was awarded Banarli licence 5104 (Valeura 100%) in the Thrace Basin. The licence had a four-year initial term and covered an area of 118,598 gross acres (185 square miles) located near the centre and deepest part of the bowl-shaped basin. In June 2013, Valeura completed a 93 kilometre 2D seismic program to complement the existing 2D seismic coverage on the licence of more than 200 kilometres. The licence is unexplored with only two relatively shallow wells drilled prior to Valeura’s ownership of the licence. The last well drilled prior to the new licence award was Karaca-1, which was plugged and abandoned at a depth of 1,026 metres in November 2010.
In Q2 2015, the GDPA approved Valeura’s application to convert the Banarli exploration licence 5104 to two new contiguous licences (F18-c1, c2, c3, c4 and F19-d1, d4) with an area of 133,840 gross acres. The initial term of the licences has been extended to June 27, 2020 under the New Petroleum Law. During the initial term, the Company will be required to complete, in aggregate on the two licences, 152 square kilometres of 3D seismic (already completed) and drill three wells, including a 2,000 metre well in each of year one and year two and a 3,800 metre well in year four. The total assigned value of this program is US$9.15 million and an associated 2% bond was submitted to the GDPA.
As of early 2015, Valeura has been pursuing a new Banarli strategy focussed on exploring the Osmancik and Mezardere formations down to a depth of approximately 2,500 metres, initially on a 100% Valeura basis. The prior strategy adopted in 2013 focussed primarily on attracting a farm-in partner to explore Banarli, particularly the deeper horizons. This change in strategy was driven primarily by the late 2014 success of the TBNG-PTI JV’s conventional gas exploration program in the Osmanli area on new 3D seismic on the TBNG-PTI JV lands immediately south of the Banarli exploration licences. The Osmanli program reinforced the value of 3D seismic in exploring for traps along the extensive fault systems in the Thrace Basin, including the ability to image trap types that had not been pursued in the past on the TBNG-PTI JV lands.
As an initial step in the new Banarli strategy, Valeura acquired 152 square kilometres of 3D seismic in the second quarter of 2015 and merged this with the 3D seismic at Osmanli and Tekirdag providing an interpreted data set covering more than 580 square kilometres.
Valeura subsequently drilled two vertical exploration wells on the Banarli exploration licences in November and December 2015.
The first of these exploration wells Bati Gurgen-1 was drilled to a depth of 2,735 metres into the top of the Teslimkoy member of the Mezardere formation, with the primary target being conventional gas in the Osmancik formation. The relatively tight Teslimkoy member was first evaluated with a diagnostic fracture injection test which confirmed that the Teslimkoy member is over-pressured. However, the net pay encountered to this depth in the Teslimkoy member was not sufficient to warrant a frac. The well was therefore completed in the Osmancik formation at a depth of approximately 1,500 metres and flowed at a restricted rate of 3.4 MMcf/d on a 24-hour production test in December 2015. The well was tied-in to a TBNG JV dehydration facility located about 3 kilometres away and first natural gas sales were achieved on March 12, 2016. In Q2 2016, production averaged approximately 2.4 MMcf/d. The gas is being sold to the TBNG JV, which in turn is distributing the gas to its existing customer base. The Danismen formation located above the Osmancik formation also appears attractive based on log analysis and will likely also be completed in the coming months.
The second exploration well Yayli-1 was drilled to a depth of 2,914 metres penetrating an attractive interval in the Osmancik formation with shallow gas potential. The well also penetrated multiple over-pressured, tighter stacked sands in the Teslimkoy member. A diagnostic fracture injection test confirmed that this Teslimkoy interval is over-pressured to the same extent as encountered in the Bati Gurgen-1 well. Two small fracs were completed in the over-pressured sands in the Teslimkoy formation at a depth of 2,700 to 2,900 metres and both confirmed producible gas. The Teslimkoy has been plugged off and a completion program in the shallower Osmancik continues.
Valeura spudded the third Banarli well at Bati Gurgen-2 on June 19, 2016, which required sidetracking and was drilled and cased to a depth of 1,857 metres (TVD). The well has been completed as an Osmancik producer after the well flowed at 1.0 MMcf/d on a 12-hour production test. The well has been tied into the gathering system and was placed on-stream in late September 2016 the IP30 rate on the Bati Gurgen-2 well was approximately 1.1 MMcf/d. In early November 2016, the Bati Gurgen-1 and 2 wells were producing an aggregate rate of approximately 2.7 MMcf/d.
Valeura continues to believe that there is significant upside potential for an unconventional basin-centred gas play in the deeper horizons at Banarli below about 2,500 metres. The results from the Bati Gurgen-1 and Yayli-1 wells have provided encouraging confirmatory data points but further drilling and production testing will be required to prove up the play. Below 2,500 metres, the source rock shales and reservoir sands could be in an active hydrocarbon-generating “kitchen” forming a basin-centered gas accumulation, with regionally pervasive, low permeability, gas-saturated sandstone reservoirs exhibiting abnormally high pressures.
In parallel with its initial 100% funded drilling program in the shallow formations on the Banarli exploration licences, Valeura has had an active process underway to seek a farm-in partner to more extensively explore the deeper horizons below 2,500 metres on the Banarli exploration licences. The TBNG JV also had active discussions underway concerning a potential farm-in on the deeper horizons on certain TBNG JV lands also targeting a potential basin-centered gas play. On May 15, 2016 Valeura announced that it had signed a binding letter agreement with Statoil for a farm-in agreement for the exploration of the deeper formations below 2,500 metres on the Banarli licenses. On October 13, 2016, Valeura announced the West Thrace Deep Rights Sale to Statoil further expanding the joint venture relationship with Statoil to explore the deeper horizons in the Thrace Basin.
Otto Producing Asset Purchase
The assets acquired from Otto in 2010 under the Edirne Acquisition Agreement initially consisted of a 35% working interest in the Edirne Exploration Licence 3839 (the “Edirne Licence”) in the Thrace Basin. In the fourth quarter of 2014, the Edirne Licence was converted to three smaller production leases (E17-b4-1, E17-c1-1 and E17-c2-1) under the New Petroleum Law. As at December 31, 2015, Valeura had net acreage in the three production leases of 17,459 acres. An affiliate of TransAtlantic operates the Edirne assets.
Gas sales from the Edirne assets in Q2 2016 averaged 0.08 MMcf/d (gross) or 0.03 MMcf/d (net). Average realized prices for Valeura’s gas sales from the Edirne Licence were $7.20 per Mcf in Q2 2016.
Natural gas is currently produced from three wells that are completed in Tertiary-aged sands in the Osmancik formation at a depth of approximately 300 metres. The gas is relatively lean and requires only dehydration and compression to meet sales specifications. The gas is processed on a fee basis in a third-party owned facility and is tied into the pipeline system operated by BOTAS located nine kilometres from the plant, which carries imported Russian gas to the Istanbul area and other cities in Turkey. The gas is sold to one of Turkey’s largest gas and power wholesalers. Sales from the Edirne assets began in April 2010. Sales from the Edirne Licence began in April 2010.
In 2014 and 2015, there was no drilling carried out given the maturity of the asset and limited exploration or development drilling opportunities.
In June 2011 as part of the TBNG-PTI acquisition, Valeura acquired a 26% non-operated interest in five exploration licences in the Anatolian Basin located around the city of Gaziantep. One of these licences (4638) was subsequently relinquished in November 2011 and an additional three licences (4648, 4649 and 4656) were relinquished in October 2013 while Gaziantep Licence 4607 (the “Gaziantep Licence”) was retained.
In July 2012, a 414 metre horizontal sidetrack was drilled in the Alibey-1 well on the Gaziantep Licence, aimed at improving productivity from a Mardin Group heavy oil discovery in the original well. Approximately 80 metres of horizontal porous section was identified on logs, with extensive natural fracturing throughout the horizontal section. The sidetrack, which is at a true vertical depth of approximately 1,868 metres, was cased with a 4.5-inch liner. In the second quarter of 2013, all of the indicated pay in the well was perforated and acidized. However, initial testing indicated oil rates of 10 to 15 bbl/d at a high water cut. Further evaluation continues to assess the merits of a recompletion program to potentially reduce water production from the well.
In the fourth quarter of 2014, the Gaziantep Licence was converted to two larger exploration licences (N39-a1, a4 and N39-d1, d2) under the New Petroleum Law, comprising 39,549 net acres.