TBNG JV Producing Assets
The TBNG JV lands (Valeura 40%) acquired 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.
In the first quarter of 2017, the TBNG JV was awarded two new production leases (F19-d3-1 and F19-c3-1) over part of expired licences 3934 and 4126.
Natural gas is currently produced from both conventional and unconventional (tight gas) sandstone reservoirs in the leases and licences on the TBNG JV lands.
The TBNG JV has had an active exploration and development program, particularly over the 2011 to 2014 period as described below. In 2015 and 2016, the activity level was reduced as the TBNG JV partners redirected cash flow to other opportunities outside the TBNG JV. In the case of Valeura, cash flow from the TBNG JV was directed to the initiation of an exploration and development program on the Banarli Licences. Nonetheless, opportunities exist to further exploit the shallow gas and tight resource potential on the TBNG JV lands through exploration and development drilling, well workovers, and additional wellhead compression to mitigate natural declines. As a result of the TBNG Acquisition, Valeura has ramped-up the exploration and development program on the TBNG JV lands in 2017.
Conventional Shallow Gas
As at March 31, 2017, 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. TBNG 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 conventional shallow gas resource on the TBNG JV lands. In summary, the following table illustrates programs that were completed over the 2012 to 2017 year to date period:
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.
2015: One development vertical drill well (gross) drilled as an appraisal well in the Osmanli area and nine well workovers.
2016: One well workover.
2017 YTD: 27 well workovers and five new shallow gas exploration wells (gross) (three on-stream; two completing/evaluating).
Opportunities exist to ramp-up the shallow, conventional gas exploration and development program, as planned by Valeura in 2017. In particular, new 3D seismic has assisted in identifying new gas exploration play types. 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 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.
Increasingly sophisticated seismic interpretation techniques have been applied to the Hayrabolu, Tekirdag and Osmanli 3D seismic surveys and have identified a number of new drilling opportunities which are expected to be pursued in 2017 and future years.
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 tight gas play. As at December 31, 2016, approximately 40% of the natural gas produced from the TBNG JV lands was tight gas produced from approximately 32 wells.
In summary, the following programs were completed to exploit the unconventional tight gas on the TBNG JV lands over the 2012 to 2017 year to date period:
2012; 11 vertical exploration and development drill wells (gross), of which the deepest 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).
2011-2014: 73 fraced 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 fracs in lower porosity intervals in the Osmancik formation.
Opportunities exist to pursue further tight gas development particularly in the Tekirdag field and a potential development plan consisting of more than 62 wells has been defined and underpins the proved, probable and possible reserves in this field.
The West Thrace Deep Rights Sale adds potential for a more active deep exploration program on the West Thrace lands, which have potential for an over-pressured basin-centered gas play, likely following Statoil’s completion of the Banarli Farm-in program.
The Company's conventional shallow gas (red) and unconventional tight gas (green) drilling program in 2012 to 2017 year-to-date period on the TBNG JV lands is illustrated in the figure and table below.
TBNG JV New Drill Spuds in 2012 – 2017 YTD
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 the second quarter of 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. To date, all the required 3D seismic programs and drilling programs have been completed with the deep well commitment being satisfied by the Yamalik-1 well under the Banarli Farm-in.
Conventional Shallow Gas
Commencing in 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 on a 100% Valeura basis. As an initial step in this 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 and a third well in June 2016.
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. The Bati Gurgen-1 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. The gas is being sold to the TBNG JV, which in turn is being distributed to its existing customer base. The Bati Gurgen-1 well produced at an average restricted IP30 rate of 3.4 MMcf/d.
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 tight gas sands in the Teslimkoy formation in the Yayli-1 well at a depth of 2,700 to 2,900 metres, each of which achieved initial gas flow but the flow could not be sustained. A completion in the shallower Osmancik formation was not successful due to high water production. The Yayli-1 well is currently suspended, but has provided important information in exploring for unconventional natural gas in the deep horizons and attracting a joint venture partner.
The third exploration well, Bati Gurgen-2, was drilled to a depth or 2,226 metres but the target Danismen and Osmancik were deeper than expected. A successful sidetrack drilling operation was then carried out and the Osmancik formation was completed and the Bati Gurgen-2 well was placed on production on September 26, 2016. The Bati Gurgen-2 well produced at an average restricted IP30 rate of 1.1MMcf/d.
Gas sales from the Banarli Licences in 2016 averaged 1.8 MMcf/d (gross and net). Oil and natural gas liquids sales totalled 4 bbl/d (gross and net). Average realized prices for Valeura’s gas sales from the Banarli Licences were $8.79 per Mcf in 2016.
Unconventional Tight Gas
Valeura continues to believe that there is significant upside potential for an unconventional basin-centered gas accumulation play in the deeper horizons below 2,500 metres in a potential pressure-seal area of more than 1,500 square kilometers proximal to the centre of the Thrace Basin encompassing the Banarli Licences and the West Thrace lands. The over-pressure measurements in the Bati Gurgen-1 and Yayli-1 wells and gas flows achieved from two small fracs in the Yayli-1 well have provided further encouraging 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 in this potential pressure-seal area 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 contrast, the tight gas formations being developed to-date on the South Thrace lands have been normally-pressured.
The first deep exploration well, Yamalik-1, under Phase 1 of the Banarli Farm-in agreement with its partner Statoil commenced drilling on May 13, 2017 and was rig released on July 22, 2017, with positive evaluation results. A completion, multi-stage fracing and testing program is expected to begin by early Q4 2017. The acquisition stage of the 3D seismic program under Phase 2 of the Banarli Farm-in commenced on June 18, 2017. A second well (Phase 3) must be funded by Statoil in order to earn a 50% participating interest in the deep formations. Valeura retains a 100% participating interest in the shallow formations to a depth of 2,500 metres. Valeura will operate this deep exploration program during Statoil’s earning phase at the same time as it continues to operate the shallow gas program on the Banarli Licences.
In summary, the following programs were completed to exploit conventional shallow gas in the Danismen and Osmancik formations and unconventional tight gas in the Osmancik, Mezardere, Teslimkoy and Kesan formations on the Banarli Licences:
2015: 152 square kilometres of 3D seismic, two exploration wells at Bati Gurgen-1 and Yayli-1.
2016: One exploration well at Bati Gurgen-2, two fracs in the Yayli-1 well and one re-completion in the Bati Gurgen-1 well.
2017 YTD: One deep exploration well drilled at Yamalik-1 and acquisition of 500 square kilometres of 3D seismic on the Banarli licences and the TBNG JV West Thrace lands commenced (both funded by Statoil under the Banarli Farm-in Agreement).
In 2010, Valeura acquired a 35% non-operated working interest in the Edirne Exploration Licence 3839 in the Thrace Basin from a wholly-owned affiliate of Otto Energy Ltd. In the fourth quarter of 2014, Edirne Exploration Licence 3839 was converted under the New Petroleum Law into three production leases in quadrants E17-b4-1, E17-c1-1 and E17-c2-1 (collectively, the “Edirne Leases”). An affiliate of TransAtlantic operates the Edirne assets.
Gas sales from the Edirne Leases in 2016 averaged 0.04 MMcf/d (gross) or 0.01 MMcf/d (net). Average realized prices for Valeura’s gas sales from Edirne Leases were $7.43 per Mcf in 2016.
The gas at Edirne is processed (dehydration and compression) 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, and sold on a wholesale basis.
In the 2014 to 2016 period, there was no drilling carried out given the maturity of the asset and limited exploration or development drilling opportunities.
As part of the Initial TBNG Acquisition, Valeura acquired a 26% non-operated working interest in five exploration licences in the Anatolian Basin located near the city of Gaziantep. Gaziantep Exploration Licence 4638 was relinquished in 2011 and Gaziantep Exploration Licences 4648, 4649 and 4656 were relinquished in 2013. In the fourth quarter of 2014, Gaziantep Exploration Licence 4607 was converted under the New Petroleum Law into two exploration licences in quadrants N39-a1, a4 and N39-d1, d2. These licences were relinquished in January 2017 due to limited prospectivity and an impending drilling commitment.