Figure 4-16: 3D Petrel Model showing topographic structure

RPS Reserves & Contingent Resources Evaluation: Romanian Properties of Serinus Energy as at December 31, 2017

CC01512 4-18 April 5, 2018

each sand. A gross pay thickness map was modelled in Petrel and used a best guess water line based upon test and log data as the P10 limit. Generally, resistivities of less than 6 ohms-m indicate the presence of water, 7-20 ohms-m likely indicate poor quality or thin gas sands and greater than 20 ohms-m resistivity suggest the location of thicker gas sands. The P90 used the extent of strong amplitudes as the Minimum case. P50 was described as the area that connected the higher amplitude areas. Net to gross and average reservoir parameters were based upon log analyses and independent log review. Seisware/ Kingdom software was used interactively to conduct the geophysical analysis and surfaces were output using Petrel to create a 3D model.

Figure 4-16: 3D Petrel Model showing topographic structure in for stacked sands A1, A2, A3 & C1, Moftinu Field5

4.4.2 Detailed Discussion of Sand A1

The only well that has tested water in the Moftinu field is 952. The A1 “equivalent” sand in 952 provided the main support for the gas water contact. This sand tested the interval 886 meters to 895 MD and recovered sweet water with 27% fine sand (Serinus personal communication). This suggests a “water up to” depth of 768.5 meters TVD SS (886.5 meters MD). Resistivities measured between 4-6 ohms-m in this sand in this well on the original Russian laterolog and imply a good correlation of water to resistivity. The 1001 and 953 wells show good channel sands cutting into distal marine sediments. Higher resistivities suggesting a possible gas-down-to (“GDT”) of 757 and 767.5 meters TVD (887 and 885.5 meters MD) respectively in these wells. The perceived “equivalent” sands at Moftinu 50 suggests a stacked nearshore marine parasequence. The upper parasequence is perceived to be the “equivalent” A1 sand and has a resistivity of 8 ohms-m up to 824 meters TVD SS (947 meters MD). While it would appear that at, this location, the sand may possibly be gas charged, the optimistic resistivities may be due to deteriorating rock quality or mineralogical differences and until we have better information RPS regards this sand as wet. As such the GWC was chosen at 769 meters TVD SS for Sand A1.


CC01512 4-19 April 5, 2018

Interestingly the perceived “stratigraphically equivalent” A1 sand at Moftinu 1000 reads a consistently low resistivity of 5-6 ohms-m in a structural location that ought to indicate gas charge. The well twinned the legacy well Moftinu 950 where the apparent equivalent sand reads higher resistivities (16 ohms-m). This sand at Moftinu 1001 was not flagged as pay16 which suggests that the sand even if it equates depositionally to the same stratigraphic level may not communicate trap wise with the gas charged reservoirs elsewhere.

Figure 4-17: 3D Structure Map A1 showing Structural Morphology and

OWC contact (Blue) Moftinu Field5


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Figure 4-18: 3D Structure Map A1 showing Structural Morphology

Figure 4-19: Structure/amplitude Map Sand A1 showing P10, P50, and P90

polygons for Rock Volume calculation)5


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4.4.3 Detailed Discussion of Sand A2

The P10 Upside depth is governed by an possible water contact in the 952 equivalent A2 sand. The sand tested a 30 m3 load fluid with weak traces of gas: Resistivities for the A2 sand in 952 approach 9 ohms-m suggesting that the sand contains gas. At the base of the sand, resistivities deteriorate to 5 ohms-m at a point where the gamma response suggests the sandstone retains reservoir quality. This may suggest a “GWC” is proximal. The equivalent “lithostratigraphic” pick at Moftinu 50 suggests a resistivity of 4-6 ohms and reinforces the thought that water may exist up to 748 meters TVD SS at this location. At Moftinu 953, 1001 and 1000 the combination of resistivity response and gas flows without water all suggest that gas occurs down to 680 meters TVD (Moftinu 952). For these reasons the “GWC” was assigned to a depth of 730 meters TVD SS for the P10 limit. Interestingly the A2 at Moftinu 1000 which flowed gas on test at 1.3 mmcf/d has a low resistivity signature of 8 ohm-m.




CC01512 4-22 April 5, 2018

Figure 4-21: Structure Map A2 showing Structural Morphology

4.4.4 Detailed Discussion of Sand A2.2

The P10 Upside is governed by a potential gas water contact in Moftino 952. The sand encountered resistivities of 4-7 ohms-m in the A2.2 sand at 667 meters TVD SS (788 meters MD). As such, a “GWC” was placed at 667 meters TVD SS to define the P10 areal polygon. The equivalent “lithostratigraphic” sand pick @ Moftinu 50 measured a resistivity of 5-7 ohms–m suggesting a WUT at 724 meters TVD SS (847 m MD). Uncertainty exists with the correlation to A2.2 at Moftino 50 and so increased emphasis was placed on the resistivities encountered in Moftino 952 well with respect to placing the P10 polygon edge.


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Figure 4-22: Structure/amplitude Map Sand A2.2 showing P10, P50, and P90 polygons for Rock

Volume calculation)5

Figure 4-23: Structure Map A2.2 showing Structural Morphology


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4.4.5 Detailed Discussion of Sand A3 Sand A3 has only been tested in Moftinu 1001 as part of a comingled test. No water was recovered. Resistivities measured in Moftinu 1001 are in excess of 50 ohms-m. At Moftinu 953 resistivities are also reasonable and in excess of 25 ohms-m. This suggests a maximum GDT depth of 606 meters TVD SS (729 meters MD). At Moftinu 952 a possible “Water Up To” may be indicated by low resistivities of 4-6 ohms-m at 762 meters MD or 641 meters TVD SS. Resistivities of 12-14 ohms-m in the Moftinu 50 well suggest a gas-up-to (“GUT”) depth of (655 meters TVD SS (777.5 meters MD) and imply that the zone may be gassy and that the trap at this sand is not related. The P10 limit for volumetric work is placed at 630 meters TVD SS. Given the difficulty of correlating into the Moftinu 50 well we placed more emphasis on resistivities seen at Moftinu 952 when marking the limit of the P10 Polygon. The P10 is therefore conservatively drawn.

Figure 4-24: Structure Map A3 showing Structural Morphology


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4.4.6 Detailed Discussion of Sand B1

B1 has not been tested. It is a thin sand (3-4 meters thick) and shows a low resistivity of 7 ohms-m but also exhibits cross over on the neutron density log. At Moftinu 953 where the sand looks to be porous, resistivities are in excess of 25 ohms-m and suggest a GDT depth of 538 meters TVD SS (658.6 meters MD). At 952 a possible water-up-to (“WUT”) may be indicated by low resistivities of 6 ohms-m at the maximum SP deflection point at (609.8 meters TVD SS (727.8 meters MD). Resistivities of 12-14 ohms-m are seen at Moftinu 50 and imply that the zone is gassy and that the trap is not related. Given the difficulty in correlating into Moftinu 50 we placed more emphasis on Moftinu 952 as the key well when marking the limit of the P10 Polygon used to calculate input rock volumes. The P10 is therefore conservatively drawn and placed at 600 metres TVD SS.


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Figure 4-26: Structure/amplitude Map Sand B1 showing P10, P50, and P90


Figure 4-27: Structure Map B1 showing Structural Morphology


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4.4.6.1 Detailed Discussion of Sand C1

C1 has not been tested but, the sand shows high resistivities at Moftinu 1001 of approximately 150 ohms-m. At Moftinu 953 resistivities are between 9-16 ohms-m and suggest a GDT depth for both of these sands of 445 and 452 meters TVD SS respectively (581.6 and 572.7 meters MD respectively). At Moftinu 952 a possible GDT may be indicated by resistivities of 9 ohms at 601.5 meters MD (480 meters TVD SS) Resistivities of 17-18 ohms-m at Moftinu 50 imply that the zone in this well may be gassy. Given the difficulties in correlating continental / nearshore sediments to the eastern part of the structure, it is possible the sand may not equate to the sand that forms the trap on the western part of the structure. The P10 limit for volumetric work is placed at 480 meters TVD SS. Again, we placed the most emphasis on Moftinu 952 as the key well marking the limit of the P10 Polygon.

Figure 4-28: Structure/amplitude Map Sand C1 showing P10, P50, and P90



CC01512 4-28 April 5, 2018

Figure 4-29: Structure Map C1 showing Structural Morphology

HIIP volumes and recoverable volumes were calculated using a probabilistic technique utilizing the REP5TM software. Distributions of gross rock volume, net/gross ratio, porosity, water saturation and formation volume factor, condensate yield, gas shrinkage and recovery factor were input into REP5TM and probabilistic distributions of in place and recoverable volumes were generated using Monte Carlo simulation. A summary of the analysis results is presented on a zone by zone basis in Figure 4.30, Figure 4.31 and Figure 4.33.

Resulting volumes are tabulated, along with a probabilistic consolidation in Table 4-4 and Table 4-5.

Figure 4-30: Gas Initially-In-Place: A1 Zone

A1 Zone: Gas and Condensate Distributions

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Figure 4-31: Gas-Initially In-Place: A2 Zone

Figure 4-32: Gas Initially-In-Place: A2.2 Zone

Figure 4-33: Gas Initially-In-Place: A3 Zone


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A2.2 Zone: Gas and Condensate Distributions

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CC01512 4-30 April 5, 2018

Figure 4-34: Gas Initially-In-Place: B1 Zone

Figure 4-35: Gas-Initially In-Place Volumes: C1 Zone

Table 4-4: GIIP by Zone

Table 4-5: Probabilistic Consolidation of GIIP and Recoverable Volumes

B1 Zone: Gas and Condensate Distributions

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C1 Zone: Gas and Condensate Distributions

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______________________________________________________

P90 P50 P10 MeanC1 1.7 4.9 14.5 7.0 BscfB1 0.2 0.6 2.2 1.0 BscfA3 2.8 6.0 13.1 7.2 BscfA2.2 1.2 3.2 8.4 4.3 BscfA2 2.0 5.1 12.5 6.5 BscfA1 2.9 7.9 21.4 10.7 Bscf

Summary Of GIIP By Zone

P90 P50 P10 MeanGIIP 21.7 33.8 54.0 36.4 Bscf

Consolidation of Intervals: A1, A2, A2.2 A3, B1 and C1


CC01512 4-31 April 5, 2018

4.5 Production and Test Performance

Commercial production from the Moftinu field has not commenced as of year-end 2017. Separation and dehydration facilities, along with a field gathering systems are currently under construction. Both the Moftinu 1000 and 1001 wells have been flow tested and shown the ability to produce from the zones of interest.

Beginning on December 22, 2017, the Moftinu 1001 well began producing gas, as a result of an uncontrolled well event. Due to this flow, the field’s cumulative gas produced is estimated at 160 MMscf as of December 31, 2017, and 215 MMscf when the well was successfully brought under control and ceased flowing on January 6th, 2018.

Moftinu 1000 Production Testing The Miocene Sandstone, which underlies the A1, A2, and A3 intervals, was perforated from 1,077 to 1,079 mKB. Pressure recorders were run and the well was flowed at two choke settings for a total duration of 21 hours. Following the flow period, a 62-hour build-up period was conducted. Cumulative produced volumes during the test period were 0.335 MMcf (9.5 103m3) of gas and 0.2 bbl (35 liters) of condensate, representing a condensate yield of less than 1 bbl/MMcf. The final gas rate prior to shut-in was 0.370 MMcf/d at a bottom hole flowing pressure of 385 psia (2,659 kPaa). Pressure transient analysis performed by IHS indicates a reservoir permeability of 5 mD and a skin of +1.5. Late time effects are consistent with the well located within a truncated channel setting, some 40 m away from 3 boundaries. On this basis, the productive interval would be expected to stabilize at very low and uneconomic rates. No resource volumes have been assigned to the Miocene Sandstone zone.

The A2 sand, at Moftinu 1000, was initially production tested February 18-21, 2012. Perforations were placed within the intervals 790 – 796 and 782 – 786 mKB and the well was flowed at two choke settings for a total of 25 hours, followed by a 47-hour build-up period. Cumulative produced volumes during the test period were 0.932 MMscf (26.4 103m3) of gas and 2.6 bbl (416 liters) of condensate, representing a condensate yield of 2.8 bbl/MMcf. The final gas rate prior to shut-in was 1.132 MMcf/d (32.0 103m3) at a bottom hole flowing pressure of 909 psia (6264 kPaa). Pressure gauge resolution was poor, yet radial flow was identified and late-time heterogeneities/boundaries were seen. The build-up analysis, as performed by IHS, indicates a permeability of 14 mD and a skin of +8.5 with the well located in a truncated channel setting, some 90 m away from 3 boundaries. Subsequent modelling by IHS indicates the well productivity may decline quickly over the first month to 0.618 MMcf/d (17.5 103m3), assuming a flowing sandface pressure of 909 psi (6264 kPaa).

In November / December 2013 the A2 sand interval at Moftinu 1000 was tested again, results from this test were less optimistic than seen in the first test. Pressure gauges were landed and the well was flowed on variable choke sizes for 79 hours. The final measured gas rate was 0.928 MMcf/d (26.3 103m3) at a flowing pressure of 565 psi (3900 kPa). A 278-hour build-up was then conducted concluding on Dec 12th. The final recorded shut-in pressure was 889 psia (6129 kPaa); still rising, but 219 psi less than the final shut-in pressure measured in February 2012. IHS was able to match the recorded flowing and build-up pressures using a complex, 4-region radial composite model. The model showed an inner permeability of 17.5 mD and skin of +7 but the outer permeability had to be reduced to a very low value, in order to match the recorded pressures. Subsequent modelling by IHS indicates the well productivity may decline quickly over


CC01512 4-32 April 5, 2018

the first month to 0.125 MMcf/d (3.5 103m3), assuming a flowing sandface pressure of 532 psi (3876 kPaa).

In December 2017 Moftinu 1000 was re-perforated and a flow test was performed with the intention of readying the well for production. The well produced on various choke sizes over course of three days. The final measured gas rate was 1.89 MMcf/d (53.5 103m3) at a flowing pressure of 526 psi (3627 kPa).

Moftinu 1001 Production Testing The Moftinu 1001 well was spud November 10, 2014 and drilled vertically to a depth of 1,463 mKB. In March 2015, three intervals were perforated within the A1, A2, and A3 sands, as shown below in Figure 4.30.

Figure 4-36: Perforation Intervals in Moftinu 1001

Pressure recorders were landed at 714.3 mKB and a flow & build-up test was conducted from the three commingled sands. A 21/64” choke size was initially selected, which was later increased to 40/64” after 10 hours. The final gas rate was 7.2 MMcf/d (206 103m3/d) at a bottom hole flowing pressure of 1,175 psia (5610 kPag). Flowing pressures declined throughout the test however the maximum drawdown utilized was less than 5%. Cumulative produced volumes were 13.7 MMcf (388.5 103m3), 29.6 bbl (4.7 m30) of condensate and minor water 6.9 bbl (1.1 m3). The final produced condensate yield was 2.5 bbl/MMcf.

Following the main flow, a 153-hour build-up was conducted. No clear sign of reservoir pressure depletion is evident from the final and initial build-up pressures. Build-up analysis indicates a short period of radial flow, followed by a rising pressure derivative in the late time region. The rising pressure derivative suggests a degradation of the flow parameters is taking place toward the outer regions of the reservoir, likely due to one of the following:

• complex reservoir geometry

• truncation of reservoir layers due to faulting or pinch-out

• reduction of permeability and/or thickness in the outer regions


CC01512 4-33 April 5, 2018

IHS was able to match the test data using a composite reservoir model. An inner region with permeability of 300 mD, declining to 7 mD at a radius of 55 m was estimated. The wellbore skin was estimated at +8.5. A falling pressure derivative can be seen towards the end of the build-up which is most likely due to crossflow at the wellbore from this layered system. Stabilized deliverability calculations indicate the well should be able to deliver 5 MMcf/d (143 103m3/d) assuming a bottom hole flowing pressure of 1,175 psia (8099 kPaa) after 1 month of production.

Moftinu 1001 was flow tested on various choke sizes in November 2017. The final measured gas rate was 1.75 MMcf/d (49.6 103m3) at a flowing pressure of 839 psi (5875 kPa). Water rates of approximately 377 bbl/d (60 m3/d) were observed during the test and it is believed the source is the base of the A1 sand. Moftinu 1001 was re-entered in December 2017 with the intention of recompleting the well to allow the A2 and A3 sands to be selectively produced together. Beginning December 22, 2017, the Moftinu 1001 well began producing gas, as a result of an uncontrolled well event. The well had an uncontrolled flow until January 6, 2018 when it was successfully killed. Approximate cumulative gas produced during this event is estimated at 160 MMscf as of December 31, 2017, and 215 MMscf when the well ceased flowing on January 6th, 2018.

4.6 Future Development

At the current stage of field development, RPS classifies the resources in the A1, A2, and A3 sands as Reserves and the resources in the A2.2, B1, and C1 sands as Contingent Resources. The Moftinu field currently has 1 shut-in well, Moftinu 1000 with Moftinu 1001 having been recently abandoned due to the uncontrolled release event in December 2017. Moftinu 1000 is currently completed in the A1, A2, and A3 sands. Capital budgets and status reports were provided by Serinus showing current construction and installation of a gas processing plant and gathering system expected to be completed mid 2018 with production from Moftinu 1000 and a soon to be drilled Moftinu 1003 and 1007 beginning in July 2018. The Moftinu 1007 well is considered to be the replacement well for the now abandoned Moftinu 1001 well. The Serinus plan envisages drilling three development wells (Moftinu 1007, 1003 and 1004) in 2018 with production to start in July and August of that year. Following the three initial development wells, one additional well, Moftinu 1006, is planned to be drilled when production constraints allow, this is estimated to occur February 2020. The development wells are projected to TD between 1,600 and 2,400m.

The gas plant will be located adjacent to the Moftinu 1001 well site, and will deliver sales gas approximately 3 km north to the TransGaz trunk line, via a 10” pipeline. The plant will be sized for maximum capacity of 15 MMscf/d and may have the capability of future expansion to accommodate higher volumes.

4.6.1 Allocation of Consolidated GIIP and Technically Recoverable Volumes

Individual sand probabilistic distributions derived utilizing REP5TM were used to allocate the stochastically aggregated results to individual sands from the total values in Table 4-5. Table 4-6 presents the results of this allocation.


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Table 4-6: Allocation of Consolidated GIIP and Recoverable Resources

4.6.2 Field Development Plan

Serinus has provided RPS with an updated field development plan (“FDP”) for this evaluation. RPS reviewed the proposed FDP and assesses it to be reasonable. All future CAPEX forecasts and production profiles are generated in a manner that is consistent with the Serinus FDP.

Table 4-7 presents a simplified view of the Serinus FDP for reserves, and also contingent development. Planned completions in each well for each of the P90, P50, P10, C90, C50, and C10 development cases are illustrated, as are sands where no completion is possible in each well. Completion timing is not reflected in this table and is addressed in a subsequent section of this report.

Zone P90 P50 P10A1 6.112 9.723 15.847A2 3.976 6.100 9.573

A2.2 2.520 3.944 6.289A3 4.916 7.087 10.378B1 0.437 0.800 1.500C1 3.721 6.152 10.457

Stochastic Consolidation

Total21.682 33.807 54.044

Pool GIIP (Bscf) Distribution Matching REP Consolidation


CC01512 4-35 April 5, 2018

Table 4-7: Serinus Moftinu Field Development Plan

The volume of gas ultimately recoverable is a function of both technical factors governing the flow rates and gas deliverability of the gas reservoirs and economic factors governing the commerciality of potential gas recovery schemes. This section describes the methodology to determine the technical recovery factors for the reservoirs. When economic limits are applied, the volumes may be less than the technical recoverable volumes presented here.

The ultimate technical gas recovery for the Moftinu field has been estimated using an Integrated Production Model (“IPM”) which uses material balance calculation of reservoir pressure depletion calculated using commercial software developed by Petroleum Experts Ltd. (PETEXTM): MBALTM reservoir models and PROSPERTM well models linked together with GAPTM surface network flow models. GAPTM is a multiphase oil and gas optimizer tool that models the surface gathering network of field production systems. When GAPTM is linked with the PROSPERTM well models and reservoir models of MBALTM a predictive and optimized full field forecast of production can be achieved.

Well models have been calibrated based on analysis of reported production tests together with current and expected completion designs provided by Serinus. Future development wells and untested zones have been modelled based on existing completions and available reservoir data. Gathering system pipeline lengths and dimensions have been based on current constructed lines (M1000 to M1001 well site and M1001 well site to TransGaz tie-in) together with estimates of tie-

Completion Interval NO Completion Possible

M1000 M1007 M1003 M1004 M1006C1 sandB1 sandA3 sand 1 1 1

A2.2 sandA2 sand 1 1 1A1 sand 1

M1000 M1007 M1003 M1004 M1006C1 sandB1 sandA3 sand 1 1 1 1

A2.2 sandA2 sand 1 1 1 1 1A1 sand 1 1

M1000 M1007 M1003 M1004 M1006C1 sandB1 sandA3 sand 1 1 1 1

A2.2 sandA2 sand 1 1 1 1 1A1 sand 1 1 1 1

3P Case Enter 1 if Resources Assigned in FDP

Field Development Plan

1P Case Enter 1 in green if Assigned in FDP

2P Case Enter 1 if Resources Assigned in FDP

Completion Interval NO Completion Possible

M1000 M1007 M1003 M1004 M1006C1 sand 1B1 sand 1A3 sand 1 1 1

A2.2 sandA2 sand 1 1 1A1 sand 1

M1000 M1007 M1003 M1004 M1006C1 sand 1 1 1B1 sand 1 1 1A3 sand 1 1 1 1

A2.2 sand 1 1 1A2 sand 1 1 1 1 1A1 sand 1 1

M1000 M1007 M1003 M1004 M1006C1 sand 1 1 1 1B1 sand 1 1 1 1A3 sand 1 1 1 1

A2.2 sand 1 1 1A2 sand 1 1 1 1 1A1 sand 1 1 1 1

Field Development Plan

1P+1C Case

Enter 1 in green if Assigned in FDP

2P+2C Case

Enter 1 if Resources Assigned in FDP

3P+3C Case

Enter 1 if Resources Assigned in FDP


CC01512 4-36 April 5, 2018

in distances to connect development wells. At the current stage of development, the IPM model has been tuned on a level that allows for an estimated forecast using optimization algorithms and multi-phase flow correlations but does not include any history matching. This amount of tuning still allows for the modelled forecast to include variables such as back pressure, flow line bottlenecking, reservoir pressure depletion and inflow variability. In the future, as wells come on production and more fluid and reservoir data is gathered, the IPM model can be further tuned to increase predictive accuracy and replicate field operation, see Figure 4.37.

Forecasts were generated using the range of in-place volumes derived in Section 4.4 together with surface network system constraints provided by Serinus. Surface constraints include a maximum 15 MMscf/d flow rate through separation facilities and a minimum 1,500 kPa delivery pressure at the TransGaz trunk line. To account for unknown operational constraints across the separation and dehydrating facilities (currently under construction) RPS has incorporated additional pressure drop of 1,000 kPa across the facility.

Figure 4-37: Moftinu Integrated Production Model Schematic


CC01512 4-37 April 5, 2018

Production start dates by well and sand for the different cases are shown in Table 4.8. The sands contributing to Reserves are depicted in a darker green shade, whilst those contributing to Contingent Resources are depicted in a lighter green shade.

Table 4-8: Moftinu Field Development Schedule

4.6.3 Production Forecasts and Estimated Recovery

Production forecasts for the existing well Moftinu 1000 and undeveloped drilling locations Moftinu 1003, 1004, 1006 and 1007 were all generated using the GAP model

The GAP model was constrained by a maximum field production limit: production from the wells was not allowed to exceed the plant design capacity of 15 MMcf/d. In addition, a delivery pressure constraint minimum of 1,500 kPa at the TransGaz trunk line was also applied in the model along with a minimum economic limit flowrate of 40 Mcf/d for each well.

M1000 M1007 M1003 M1004 M1006C1 sand* Feb 2019B1 sand* Aug 2018A3 sand July 2018 Aug 2018 Feb 2019

A2.2 sand*A2 sand July 2018 July 2018 July 2018A1 sand July 2018

*Contingent Resources

M1000 M1007 M1003 M1004 M1006C1 sand* Feb 2019 Feb 2019 May 2020B1 sand* Feb 2019 Feb 2019 May 2020A3 sand July 2018 July 2018 Aug 2018 Feb 2020

A2.2 sand* July 2018 Aug 2018 Feb 2020A2 sand July 2018 July 2018 July 2018 Aug 2018 Feb 2020A1 sand July 2018 July 2018


M1000 M1007 M1003 M1004 M1006C1 sand* Feb 2019 Feb 2019 Feb 2019 May 2021B1 sand* Feb 2019 Feb 2019 Feb 2019 May 2021A3 sand July 2018 July 2018 Aug 2018 Feb 2021

A2.2 sand* July 2018 Aug 2018 Feb 2021A2 sand July 2018 July 2018 July 2018 Aug 2018 Feb 2021A1 sand July 2018 July 2018 Aug 2018 Feb 2021


Field Development Schedule

P90/C90 Case Estimated Start of Production

Estimated Start of Production

P50/C50 Case Estimated Start of Production

P10/C10 Case


CC01512 4-38 April 5, 2018

Forecast production for the Moftinu field is presented in Figure 4.38. The forecasts shown in the figure below are raw gas technical forecasts prior to applying any economic cut-offs & shrinkage. All volumes (for both Reserves and Contingent Resources) are shown as unrisked volumes.

Figure 4-38: Reserves + Contingent Resources Production Forecasts: Moftinu Field

The following tables describe the breakdown of unrisked produced volumes by sand for each well along with the estimated recoverable and unrecoverable volumes based on the current development plan.

0123456789

10111213141516

1/1/2018 1/1/2022 1/1/2026 1/1/2030

Rate

(MM

scf/

d)

Date

Contingent + Reserves Production Forecasts (Unrisked)

1P+1C 2P+2C 3P+3C 1P 2P 3P


CC01512 4-39 April 5, 2018

Table 4-9: Moftinu Field (Raw Gas) Estimated Volume Recoveries (Reserves)

Table 4-10: Moftinu Field (Raw) Estimated Volume Recoveries (Reserves and Contingent Resources) (Unrisked)

1P CaseRaw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+

Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf MstbC1 sand 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3.7 7.4 3.7 7.4B1 sand 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.9 0.4 0.9A3 sand 0.0 0.0 1.1 2.3 0.0 0.0 1.4 2.9 0.7 1.4 3.2 6.5 1.7 3.3 4.9 9.8

A2.2 sand 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.5 5.0 2.5 5.0A2 sand 0.04 0.07 0.7 1.5 1.8 3.6 0.0 0.0 0.0 0.0 2.6 5.2 1.4 2.8 4.0 8.0A1 sand 0.0 0.0 0.5 1.0 0.0 0.0 0.0 0.0 0.0 0.0 0.5 1.0 5.6 11.2 6.1 12.2

Total 0.04 0.07 2.4 4.7 1.8 3.6 1.4 2.9 0.7 1.4 6.3 12.7 15.3 30.7 21.7 43.4




Total 0.3 0.8 5.3 13.3 5.1 12.7 3.7 9.3 2.5 6.3 17.0 42.4 16.8 42.1 33.8 84.5




Total 0.5 1.5 8.0 24.0 7.6 22.8 6.5 19.4 2.2 6.6 24.8 74.3 29.3 87.8 54.0 162.1

Moftinu Field (Raw Gas) Technical Volume Recoveries by Case / Zone / Well

Total Field

Zone

M1000 M1007 M1003 M1004 M1006 Recoverable Unrecoverable Total Field

M1000 M1007 M1003 M1004 M1006 Recoverable Unrecoverable

M1006 Recoverable Unrecoverable Total Field

Zone

Zone

M1000 M1007 M1003 M1004

1P+1C CaseRaw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+



Total 0.04 0.1 4.1 8.2 2.2 4.4 1.6 3.2 0.7 1.4 8.6 17.3 13.1 26.1 21.7 43.4




Total 0.4 0.9 7.3 18.3 6.6 16.6 5.4 13.5 2.8 6.9 22.5 56.2 11.3 28.4 33.8 84.5




Total 0.5 1.6 11.3 33.9 10.8 32.5 8.9 26.7 4.5 13.4 36.1 108.2 18.0 54.0 54.0 162.1

Zone

Zone

M1000 M1007 M1003

Zone


M1000 M1007

Total Field

M1000 M1007 M1003 Total Field

M1003 M1004 M1006 Unrecoverable Total Field

UnrecoverableRecoverable

M1004 M1006 UnrecoverableRecoverable

Recoverable

M1004 M1006


CC01512 4-40 April 5, 2018

Table 4-11: Moftinu Field (Raw) Estimated Volume Recoveries (Contingent Increment - Unrisked)

4.7 Reserves/Resources Classification

At the current stage of field development, RPS categorizes the resources in the A1, A2, and A3 sands as Reserves and the resources in the A2.2, B1, and C1 sands as Contingent Resources.

4.8 Economic Valuation

4.8.1 Capital, Operating and Abandonment Costs

As summary of capital cost estimates for Serinus Energy’s development plans are presented in Table 4-12. These estimates are based on discussion with Serinus and supplied capital budget information.

Future operating cost estimates are projected based on information supplied by Serinus from experience in these operating environments.

1C IncrementRaw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+ Raw Gas Field C5+

Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf MstbC1 sand 0.00 0.00 2.11 4.23 0.00 0.00 0.00 0.00 0.00 0.00 2.11 4.23B1 sand 0.00 0.00 0.00 0.00 0.00 0.00 0.18 0.35 0.00 0.00 0.18 0.35A3 sand 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

A2.2 sand 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00A2 sand 0.00 0.00 -0.36 -0.73 0.37 0.73 0.00 0.00 0.00 0.00 0.00 0.00A1 sand 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Total 0.00 0.00 1.75 3.50 0.37 0.73 0.18 0.35 0.00 0.00 2.29 4.58


Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf MstbC1 sand 0.00 0.00 1.28 3.20 0.00 0.00 1.18 2.95 1.04 2.60 3.50 8.75B1 sand 0.00 0.00 0.21 0.53 0.00 0.00 0.21 0.53 0.09 0.23 0.52 1.30A3 sand 0.00 0.00 0.25 0.62 0.27 0.67 -0.43 -1.08 -0.76 -1.89 -0.67 -1.68

A2.2 sand 0.00 0.00 0.00 0.00 1.03 2.58 1.14 2.85 0.52 1.30 2.69 6.73A2 sand 0.03 0.08 0.25 0.63 0.27 0.67 -0.44 -1.09 -0.65 -1.63 -0.54 -1.34A1 sand 0.00 0.00 -0.01 -0.02 0.01 0.03 0.00 0.00 0.00 0.00 0.00 0.01

Total 0.03 0.08 1.99 4.96 1.58 3.95 1.66 4.16 0.25 0.62 5.50 13.76


Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf Mstb Bscf MstbC1 sand 0.00 0.00 1.76 5.29 1.57 4.72 1.33 4.00 1.30 3.90 5.97 17.91B1 sand 0.00 0.00 0.38 1.13 0.28 0.85 0.21 0.63 0.10 0.31 0.97 2.91A3 sand 0.00 0.00 0.41 1.23 -0.14 -0.40 -0.25 -0.74 0.02 0.06 0.05 0.15

A2.2 sand 0.00 0.00 0.00 0.00 1.81 5.44 1.67 5.02 0.81 2.42 4.29 12.88A2 sand 0.06 0.18 0.36 1.07 -0.14 -0.42 -0.25 -0.76 -0.02 -0.06 0.00 0.00A1 sand 0.00 0.00 0.39 1.17 -0.15 -0.45 -0.28 -0.83 0.05 0.14 0.01 0.01

Total 0.06 0.18 3.29 9.88 3.24 9.73 2.44 7.32 2.26 6.77 11.29 33.87

Zone


Zone

M1000 M1007 M1003 M1004 M1006 Recoverable (Increment)

Zone




CC01512 4-41 April 5, 2018

The operating costs estimates allocation is based on estimates provided by Serinus within budget documents.

Abandonment costs and reclamation cost estimates are also presented in Table 4-12. These costs are reasonable for the field conditions.

Table 4-12: Summary of Capital, Operating and Abandonment Costs

Field: MoftinuCountry: Romania

Company: Serinus EnergyCapital Interest: 100%

Capital Expenditures Assumptions

Year Description Total Field Capital

Company Share

Company Share Capital

million US$ (%) million US$

Proved Undeveloped

Q4 2018 Gas processing facility 3.68 100% 3.68Q4 2018 Reactivate Moftinu 1000 0.04 100% 0.04Q4 2018 Drill, Complete, Tie-in & commingle initial zones Monftinu-1007* 3.89 100% 3.89Q2 2018 Drill, Complete, Tie-in & commingle initial zones Monftinu-1003 3.49 100% 3.49Q2 2018 Drill, Complete , Tie-in & commingle initial zones Monftinu-1004 3.25 100% 3.25Q3 2019 Drill, Complete, Tie-in & commingle initial zones Monftinu-1006* 3.37 100% 3.37

2018 Seismic Survey 0.14 100% 0.14Total Proved Undeveloped 17.86 100% 17.86

Total 1P 17.86 100% 17.86

Probable Additional

Total Probable Additional 0.00 100% 0.00Total 2P 17.86 100% 17.86

Possible Additional

Total Possible Additional 0.00 0.00Total 3P 17.86 100% 17.86

Operating Cost Assumptions (US$ Unescalated)Field Operating Costs

Field fixed costs 2018 $0.66 M / year of operationsField fixed costs 2019 Onwards $1.04 M / year of operationsField variable costs $0.39 /Mcf (raw gas)

Field variable costs $1.09 /bbl (raw condensate)

G&A $1.03 M / year

Abandonment and Reclamation Cost Assumptions (US$ Unescalated)Field Abandonment and Reclamation

Abandonment Costs $2,081 k

Notes:Updated Facilities costs provided by Serinus based on actual spending and project award.Operating cost estimate based on Serinus 2018 budget and estimatesCost for Moftinu-1003 , 1004 & 1005 include the compeltion and commingling costs of all the initial producing zonesCapex for Moftinu 1006 scehduled for 2019 , 2020 and 2021 for the 1P , 2P and 3P cases respectivelyInsurance expected to cover 3.5 MM$US of the gross Moftinu 1007 cost

Unescalated Real 2018 $US

Reserves Category


CC01512 4-42 April 5, 2018

4.8.2 Oil and Gas Markets and Prices

Future gas pricing was determined by correlating the historical European gas price to historical Brent oil prices, then referencing the January 1, 2018 RPS forecast for Brent Crude. The gas price was calibrated to the Serinus draft gas sales agreement contract for Moftinu gas sales, which specifies a price of RON 65.0 per MW-h.

A sales gas heating value of 1,100 Btu/scf was utilized in the gas pricing model, as estimated through Serinus Energy’s facility simulation model. A gas shrinkage factor of 2%, 5%, and 8% was applied to the 1P+1C, 2P+2C, and 3P+3C cases, respectively.

Condensate pricing is set equal to RPS’ projection of Brent oil pricing.

4.8.3 Tax Assumptions

Taxation assumptions are presented in Table 4-13.

Field: Country:

Company: Capital Interest: %

Capital Expenditures Assumptions

Year Description Total Field Capital

Company Share

Company Share Capital

million US$ (%) million US$

1C

Jan 2019 Workover to perforate and commingle additional zones Monftinu-1007 0.39 100% 0.39Total 1C 0.39 100% 0.39

2C additional

Jan 2019 Workover to perforate and commingle additional zones Monftinu-1004 0.39 100% 0.39

April 2020 Workover to perforate and commingle additional zones Monftinu-1006* 0.39 100% 0.39

Total 2C Additional 0.77 100% 0.77Total 2C 1.16 100% 1.16

3C additional

Jan 2019 Workover to perforate and commingle additional zones Monftinu-1003 0.39 100% 0.39

Total 3C Additional 0.39 100% 0.39Total 3C 1.55 100% 1.55

Notes:Additional Capex for Moftinu 1006 is scehduled for 2020 and 2021 for the 2C and 3C cases respectively

Unescalated Real 2018 $US

Contingent Resources Category

Contingent Resources incremental


CC01512 4-43 April 5, 2018

Table 4-13: Summary of Tax Assumptions

4.8.4 Economic Valuation Results

Applying the production forecasts, pricing assumptions, capital, operating, and abandonment costs into an economic model in ValNav® results in the cash flow results shown in the following Table (Unrisked).

Table 4-14: Economic Valuation Results (Unrisked Results)

Summary of Taxation Assumptions

Field : MoftinuCountry: Romania

Location : Onshore

(US$ basis)*Tax Loss carry forward @ December 31 , 2017 $10.19 million*Undepreciated Capital @ December 31 , 2017 $32.63 millionIncome tax rate 16%Royalty rate Sliding scale, dependent on production rate

* 5 year straight line applied to undepreciated capital

Satu Mare Field: Serinus 100% Working Interest & Financing Reserves Volumes and Values

Company Share

CategoryNet Reserves

(Mboe) 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%

PUD 956 11.8 10.8 9.9 9.1 8.4 11.8 10.8 9.9 9.1 8.4

100% 1P 956 11.8 10.8 9.9 9.1 8.4 11.8 10.8 9.9 9.1 8.4WI

Satu Mare 2P 2,323 56.2 50.4 45.4 41.2 37.5 52.1 46.7 42.1 38.2 34.7

3P 3,563 100.7 86.8 75.5 66.2 58.6 91.1 78.6 68.4 60.1 53.1

Net Present Value After Tax

Company Share (Million US$) Company Share (Million US$)

Net Present Value Before Tax

Satu Mare Field: Serinus 100% Working Interest & Financing Resources Volumes and Values

Company Share

CategoryNet Resources

(Mboe) 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%

Undeveloped 287 6.7 6.2 5.7 5.2 4.8 6.3 5.8 5.3 4.9 4.5

100% 1C 287 6.7 6.2 5.7 5.2 4.8 6.3 5.8 5.3 4.9 4.5WI

Satu Mare 2C 990 33.5 27.5 22.8 19.1 16.1 29.6 24.3 20.1 16.8 14.1Unrisked

3C 1,607 60.2 44.5 33.4 25.5 19.6 50.7 37.5 28.2 21.4 16.5

Net Present Value Before Tax Net Present Value After Tax



CC01512 4-44 April 5, 2018

Detailed unrisked cash flow outputs from the economic model using the Forecast Case are presented in Table 4-16 to Table 4-21 for the three reserves and resource levels.

4.9 Risk Analysis for Chance of Development

The Chance of Development (“COD”) is the probability that a resource, once it has been discovered, will ultimately be commercially developed, considering the risks of (i) a viable established recovery technology being identified, available, and performing adequately, (ii) the economics being viable, (iii) a development plan being in place, (iv) development occurring within a reasonable timeframe, and (iv) other contingencies which may be necessary to overcome (such as political risk, market access, and regulatory and environmental approvals) for the project to proceed.

In the case of Moftinu, the main contingency which needs to be overcome with respect to the potential producing zones in the Contingent Resources category is the establishment, through production testing, of the ability of these zones to produce gas at commercial rates. COD has been estimated using the factors described above, and RPS’ considers the COD for the Moftinu project at the current advanced stage of planning to be 90%.

4.10 Risk Discounted Valuation

Utilizing the above Chance of Development and applying it only to the Contingent Resources Volumes and net present values results in the following table of results.

Table 4-15: Economic Valuation Results (Risked Results)

Satu Mare Field: Serinus 100% Working Interest & Financing Resources Volumes and ValuesCompany Share

CategoryNet Resources

(Mboe) 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%

Undeveloped Risked 258 6.1 5.5 5.1 4.7 4.3 5.7 5.2 4.8 4.4 4.1

100% 1C Risked 258 6.1 5.5 5.1 4.7 4.3 5.7 5.2 4.8 4.4 4.1WI

Satu Mare 2C Risked 891 30.1 24.7 20.5 17.2 14.5 26.7 21.9 18.1 15.1 12.7Risked

3C Risked 1,446 54.2 40.1 30.1 22.9 17.7 45.6 33.8 25.3 19.3 14.9

Net Present Value Before Tax - Risked Net Present Value After Tax - Risked



CC01512 4-45 April 5, 2018

TABLES


CC01512 4-46 April 5, 2018

Table 4-16: Moftinu 1P Reserves, Production and Cash Flow


CC01512 4-47 April 5, 2018

Table 4-17: Moftinu 2P Reserves, Production and Cash Flow


CC01512 4-48 April 5, 2018

Table 4-18: 3P Reserves, Production and Cash Flow


CC01512 4-49 April 5, 2018

Table 4-19: Moftinu 1C Contingent Resources, Production and Cash Flow (Unrisked)


CC01512 4-50 April 5, 2018

Table 4-20: Moftinu 2C Contingent Resources, Production and Cash Flow (Unrisked)


CC01512 4-51 April 5, 2018

Table 4-21: 3C Contingent Resources, Production and Cash Flow (Unrisked)


CC01512 5-1 April 5, 2018

5.0 REFERENCES

1 Dolton, G. 2006 “Pannonian Basins Province Central Europe (Province 4804) Petroleum Geology, Total Petroleum Systems and Petroleum Resource Assessment Bulletin” : 2204-B USGS. 2 East West Petroleums (undated) “Romanian Basin Outstanding Opportunity” . 3 Ciulavu, D., Dinu C, and Cloetingh A.S.P.L 2002 “Late Cenozoic Tectonic Evolution of the Transylvanian basin and Northeastern part of the Pannonian Basin (Romania)” : Constraints from Seismic Profiling EGU Stephan Mueller special publication Series 3 105-120 2002 European Geosciences Union 4 Burchfield B.C and Royden L, 1982 “Carpathian Foreland and Thrust Belt and Its Relation to Pannonian and Other Basins” : AAPG Bull V66 No 9 (September). 5 Magyar .I, Radivojevic D, Sztano O, Ratstislav .S, Ujszaszi .K, and Pocsik .M, 2012 “Progradation of the Paleo Danube Shelf margin across the Pannonian Basin during the Late Miocene and Early Pliocene” : Global and Planetary Change: doi 10.1016/j.globplacha.2012.06.07. 6 Serinus 2015a – “Satu Mare Overview September 2015”: Serinus Internal Review. 7 Serinus 2015b – “Moftinu Reservoir Study 2015” : Submission to NAMR. 8 Serinus Energy 2013 “Proven performance with Room to Run” : Serinus Energy November 27 2013. Public Promotional Material. 9 Windstar 2012 “Satu Mare Concession Agreement Between Rom Petrol and the National Agency for Mineral Resources” : Serinus Energy Internal Document dated 2003 10 RPS Energy Canada Ltd., 2014 – “Prospective Resource Evaluation of the Satu Mare License, Romania Reserves and Resource Evaluation” : Report Generated for Serinus Energy July 1 2013 11 Winstar and RomPetrol 2013 “Geoscience Summary Satu Mare Concession October 2013” 12 Dolby, G. 2015, “Palynological Analysis of Moftinu 1001 and 1002bis Romania” : Prepared for Serinus Energy August 2015. 13 Cant, D.,1984 “Subsurface Facies Analysis” In “Facies Models”. 14 Galloway, W.E., 1989, “Genetic Stratigraphic Sequences in Basin Analysis. I. Architecture and Genesis of Flooding-Surface Bounded Depositional Units”: American Association of Petroleum Geologists Bulletin 73, 125–142. 15 Everett, R. 2015a, “Petrophysics Designed to Honour Core, Moftinu 1000, 1001, 1002 Petrophysical Report and TIF Plot” Robert V Everett Petrophysics Inc. 16 Cumbria Resources 2012 “Moftinu 1000 DRF Quicklook Analysis 2012”. 17 Everett, R.V. 2015c “Three Methods for Log derived minerology Part 1 Primarily used for Shales (silts) and Tight Formations and also applicable to High Porosity Formations” : Canadian well Logging Society Insight CWLS Magazine Spring 2014.

http://www.sepmstrata.org/Terminology.aspx?id=genetic%20sequence

http://www.sepmstrata.org/Terminology.aspx?id=genetic%20sequence


CC01512 5-2 April 5, 2018

18 Herron, M.M. Johnson, D.L and Schwatz, l.M. 1998 “Robust Permeability Estimator for Silicilastics” SPE 49301. 19 Herron, S.L and Herron, M 2000 “Application of Nuclear Spectroscopy Logs to the Derivation of Formation Matrix Density”. : 41st Annual Logging Symposium Soc well Log Analyst Jun 4-07 Dallas. 20 Everett, R. 2014, “Sabria Field Win 12 Biz Runs 1,2 and 3 Petrophysical Report and TIF Plot”

21 MacPherson Company 2015 “Petrophysical Study of Moftinu 1001 and 1002 bis” : MacPherson.R.


CC01512 Appendix April 5, 2018

APPENDIX A LIST OF ABBREVIATIONS

API Oil gravity in American Petroleum Institute (API) units bbl Barrels Bcf billions of cubic feet Boe barrels of oil equivalent bpd barrels per day Btu British thermal unit DST Drill Stem Test d Day EWT Extended Well Test GDT Gas-down-to GIIP Gas Initially-In-Place GOC Gas-Oil-Contact GOR Gas/Oil Ratio GORR Gross Overriding Royalty GRV Gross Rods Volume GUT Gas-up-to GWC Gas-Water Contact 1P Proved 2P Proved + Probable 3P Proved + Probable + Possible km Kilometres HIIP Hydrocarbons Initially in Place kPa Kilopascals LOF Life of Field m Metres M Thousand mD Permeability in millidarcies mKB measured well depth in metres, referenced to drilling rig kelly bushing. MM Million MMcfd millions of cubic feet per day MMbbl millions of barrels MMboe millions of barrels of oil equivalent NPV Net Present Value OWC Oil Water Contact OIIP Oil Initially In Place P10 10% Statistical Confidence Level of Value referenced P50 50% Statistical Confidence Level of Value referenced P90 90% Statistical Confidence Level of Value referenced scf standard cubic feet scf/d standard cubic feet per day stb stock tank barrels stb/d stock tank barrels per day STOIIP Stock Tank Oil Initially In Place TVDSS True Vertical Depth Subsea WI Working Interest WUT Water-up-to


CC01512 Appendix April 5, 2018

APPENDIX B MOFTINU GEOLOGICAL MAPPING

A1 Sand P90

M1006

M-1006 is the new suggested future well location replacing the old suggested location of M-1005

A1 Sand P50

M1006


A1 Sand P10

M1006


A2 Sand P90

M1006


A2 Sand P50

M1006


A2 Sand P10

M1006


A2.2 Sand P90

M1006


A2.2 Sand P50

M1006


A2.2 Sand P10

M1006


A3 Sand P90

M1006


A3 Sand P50

M1006


A3 Sand P10

M1006


B1 Sand P90

M1006


B1 Sand P50

M1006


B1 Sand P10

M1006


C1 Sand P90

M1006


C1 Sand P50

M1006


C1 Sand P10

M1006


Documents

Figure 4-16: 3D Petrel Model showing topographic structure