Executive Summary of Competent Person's Report

11 May 2018

Urals Energy PCL ("Urals Energy" or the "Company")
Executive Summary of Competent Person's Report

The board (the "Board") of Urals Energy PCL (AIM: UEN), the independent oil and gas exploration and production company with operations in Russia, is pleased to announce that the Executive Summary of the Competent Person's Report (the "CPR") prepared by Blackwatch Petroleum Services Ltd ("Blackwatch") will shortly be published on the Company's web site - www.uralsenergy.com  

The text of Executive Summary of the CPR is reproduced below, excluding images.

Competent Person's Report for Certain Assets in the Russian Federation.  Prepared for Urals Energy Public Company Limited

 

The Directors
Urals Energy Public Company Limited
Moscow,

Dear Sirs,

Subject: Competent Person's Report for Certain Assets in the Russian Federation

In accordance with your instructions, we have conducted a Technical Reserves & Resource Assessment of certain assets of Urals Energy Public Company Limited ("Urals") in Siberia, and have compiled herewith a Competent Person's Report (CPR).

The primary basis for our assessment was a package of data made available by Urals. Where possible, we have undertaken a review/audit of the technical work carried out by Urals and their advisors and third party consultants that worked on the assets for Urals. We have carried out independent estimates of reserves, contingent resources and prospective resources and our findings are summarised herein. In estimating hydrocarbons in place and recoverable volumes, we have used the standard geoscience and petroleum engineering techniques. These combine geophysical and geological knowledge with detailed information concerning porosity and permeability distributions, reservoir temperature and pressure conditions and fluid characteristics.

There is of course uncertainty inherent in the measurement and interpretation of basic data. We have estimated the degree of this uncertainty and have used statistical methods to calculate the range of hydrocarbons initially in place or recoverable. It should be understood that any technical assessment, particularly one involving exploration and future petroleum developments, may be subject to significant variations over time as new information become available. The resources included in this evaluation are therefore estimates and should not be construed as exact quantities. We have classified the prospective hydrocarbons according to the SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS), an excerpt of which is included in Appendix 1 of this CPR. The content of this report and our estimates of resources are based on data provided to us by Urals.

Part-1) Executive Summary

Urals is a Cyprus-based E&P holding company focused on operations in the Russian Federation. The company currently operates the following 6 E&P licenses in Siberia:

  • North on Kolguyev island (2 licenses in Peschanoozerskoe) - operated by Arcticneft
  • East of Sakhalin island (2 licenses; Okruzhnoe & South Dagi) - operated by Petrosakh
  • Komi Republic (2 licenses; Baberssky & Ordynsky) - Operated by BVN Oil & RK Oil respectively

I) Petrosach

I.i) Overview1

Petrosakh was founded in 1991 as a Russian-U.S. joint venture to develop the Okruzhnoye field on the Eastern coast of Sakhalin Island. In 1993 and subsequently in 1997, Petrosakh was licensed to produce oil from the Okruzhnoye field for a period of 20 years. The Company acquired full control of Alfa Group's ownership interest in Petrosakh on 19 November 2004. In 2012, the Company secured an extension of the licence until 2037. In June 2016 Petrosakh was awarded a 25-year exploration and development license for the South Dagi oil field on Sakhalin Island. Urals holds 97.16% of Petrosackh and the balance is held by the administration of Sakhalin Island.

Twenty-five producing wells have been drilled to date in Petrosakh area of operations, split as follows:

  • 3 gas lift
  • 4 natural flow
  • 18 artificial lift

I-ii) Okruzhnoye

Okruzhnoye field structure is a "tight" asymmetric anticline trending NNW sub-parallel to the coast, bounded and segmented by steep faults. The field at its maximum extent is approximately 7Km long 1.5 Km wide with a vertical closure of about 700m.

There are two main reservoirs in Okruzhnoye; 'Borsky' and the 'Pileng'. The Pileng is Stacked Palaeogene and it contains the majority of the reserves. The Borsky is a Miocene reservoir. Maps indicate long hydrocarbon columns present in the Pileng and Borsky reservoir zones. The Pileng is a highly fractured siliceous clay composed of authigenic silica in a globular form in a (montmorillonite - illite) clay matrix that also contains pyroclastics and subordinate terrigenous feldspar and quartz. The abundant silica is believed to be derived from diatoms and sponge spicules and exhibits micro-porosity. Overall this reservoir interval exhibits fair porosity (11-17%) and relies to a large extent on fracturing at all scales for permeability. Similarly, the Borsky (four reservoir zones with intervening shale seal) is a very low matrix permeability (2-3 mD), siliceous and argillaceous, silty shale but naturally fractured. The dual matrix/ fracture poro-perm system creates difficulties for production in that the main storage lies within moderate porosity but low permeability matrix whereas the fracture system is high permeability but with little porosity and storage capacity.

In total, there are 5 commercially productive horizons, Pileng IV, Borsky IV, IIIa, III, and II. These occur at depths of between 1200m and 1810m below surface. The reservoirs contain good quality light oil with 36.5 - 37.5°API low paraffin (1.08%) and sulphur (0.24%). Crude sold with US$2-3/bbl premium to Dubai benchmark. Since, productivity from both reservoir intervals is related to the density of open fractures, water breakthrough may be problematic and may affect sweep efficiency and economic recovery. Production has shown no/very weak aquifer support during depletion, hence, optimisation of water-flooding and placement of wells to minimise draw down during production is critical in maximizing recovery.

I-iii) South Dagi

The South Dagi Field is located in the north-eastern part of Sakhalin, in a hilly area (elevation 25-776m abmsl) onshore Sakhalin Island at the southern end of the Sakhalin Ridge and lies within the Nogliki region 4 km SW of eastern Dagi and 6 km west of Mongi (largest onshore deposit in North Sakhalin). The field was discovered in 1977/78. Petrosakh was awarded a 25year exploration and development licence for South Dagi oilfield in June 2016.

Urals2 has spudded its first well, a planned exploration well, at the South Dagi field on Sakhalin Island. The well's target pay horizons are the Okobycay horizon and the Daginsky neogenic horizon, with the target depth being 2,200 meters. It is anticipated that this depth will be reached in the second quarter of 2018. The company intends for this well to be the first well in a programme of three exploration wells at South Dagi over 2018 and 2019, which are to be drilled by Urals Energy's own team using the rig that was recently acquired from Jereh Group. Any oil production from South Dagi can be transported by road tanker to the Company's refinery at Petrosakh, a distance of 400 kms, which would increase the utilisation rate of the Company's refinery. The refinery will not need additional investment to process both the heavy and light oils expected from South Dagi. In addition to the drilling programme mentioned above, the company plans to workover two wells in order to reach the target capacity.

The South Dagi field has been mapped from 3D data and covers an area of approximately 29Km2. The 3D data quality appears good to fair. Blackwatch did not have data cube and grids, hence could not verify the interpretation. Similarly, we did not verify depth mapping and have not reviewed velocity/depth relationship. However, the interpretation appears reasonable based on the review that we carried out. Micro-seismic has also been acquired showing possible upside potential to the east of the currently defined development area.

The South Dagi field is structurally complex (part of a Cenozoic accretionary wedge). The field structure is a NNE trending (transpressive) anticline that is strongly segmented by normal NNE-SSW trending oblique -slip faults. Blackwatch found the interpretation on selected illustrative seismic lines satisfactory but has not accessed the 3D data cube to carry out an in-depth assessment of the geophysical interpretation.  Similarly, we cannot verify depth mapping and have not reviewed the velocity / depth relationship. However, the structural interpretation appears reasonable though structural complexity and compartmentalisation of the productive horizons may be greater than currently shown. Consequently, drainage volumes may be smaller than currently envisaged and require a high number of wells to maximize recovery. 

Gas-oil (GOC) and oil-water (OWC) contacts are constrained by drilling though there remains significant uncertainty in the maximum hydrocarbon column height of some productive intervals (since there are few penetrations of OWC's and numerous penetrations record oil-down-to (ODT)). Hydrocarbon columns in some fault panels have not yet been proved by drilling.  The maps show reasonable estimates of the degree of hydrocarbon fill based on the data available. Possible variations in column heights were taken into account within the range of gross rock volumes (GRV) estimated.  

The reservoir comprises thin, stacked Neogene (Middle Miocene- Pliocene) sandstones (12 zones identified as hydrocarbon - bearing) of continental to shallow marine (transgressive) origin. The principal zones lie within the Okobykajskim and Daginskaja and are composed of a frameworks of quartz, feldspar and chert, with cements of chlorite, kaolinite, carbonate, and quartz with variable proportion of montmorillonite clay matrix.  It is unclear whether the complex faulting is entirely post- depositional or if reservoir thickness changes significantly across some faults, i.e there was syn-depositional structural control.  For volumetric estimates Blackwatch used the penetrated thicknesses in wells as the primary reference and assumed a range of low-medium and high thicknesses constant within each fault panel evaluated in order to derive GRV. Seismic resolution does not appear to be sufficient to map directly top and base of the individual pay sections though as stated above Blackwatch did not load or re-interpret the 3D data cube which was beyond the scope of this review. Porosity is typically good (circa 20%) and permeability variable from fair to excellent (up to darcies).

No direct hydrocarbon indicators have been observed / mapped. However, given the good sandstone porosities proved by drilling together with the likely velocity and density contrasts with interbedded shales and modest burial depth (1000-2020m below surface), Blackwatch would expect some direct hydrocarbon indications in the seismic data. It was not clear whether AVO and fluid substitution modelling has been attempted but potentially they might provide useful input to reduce risk and better define the distribution of trapped hydrocarbons.

Blackwatch loaded selected seismic data (2D lines and 3D images) together with geo-rectified maps to Kingdom workstation in order to make independent volumetric assessment. Our review has shown that previous mapping and input parameters are acceptable. The data shows that there is significant variability in physical characteristics of 36.5-37.5°API oil trapped in the field, (high viscosity in the shallow upper zones and low viscosity in deeper levels. The oil is sweet low in sulphur (0.24%) and paraffin but high in resins (in common with other North Sakhalin oils). Both saturated (with gas caps) and under-saturated oils are reported. Some shallow gas caps are probably methane generated from biodegradation of the underlying oil. It is also reported that there is no aquifer support and Gas is re-injected and / or flared. 

Regionally source rocks are known in Miocene and Oligocene shales containing type II and type III organic matter with a total organic content (TOC of <1% to 5%), whilst some authors attribute resources in North Sakhalin to deep marine oozes of Lower Miocene - Oligocene.  Present geothermal gradients across the North Sakhalin Basin range from approximately 24° to 50° C/km (1.3°-2.7° F/100 ft), and heat flow is irregular along the major fault zones. The oil and gas window therefore falls within a range of 2.5km to 4 km and peak generation, maturation and migration was likely in Late Miocene to Pliocene time. Migration paths to South Dagi were probably short lateral distances with significant vertical distances along faults, particularly along the major regional shears. Pleistocene leakage along these faults, has resulted in the traps being under-filled relative to their spill points. The shaly Upper Miocene - Pliocene provides good top seal regionally whereas interbedded shales within the objective intervals also provide local seal. Shale smear on oblique slip faults is also likely to compartmentalize the structure. Structural and stratigraphic complexity (stacked reservoirs) together with large variations in oil, gas and condensate mobility suggest a detailed integrated G&G (geophysical, Geological), petrophysical and engineering study is required to revise field description and refine volumetric estimates of resources. Information from the proposed drilling programme will also yield crucial information.

II) Articneft - Peschanoozerskoye

Arcticneft is a Russian closed joint stock company incorporated in 1998 in order to develop the the eastern and western parts of the Peschanoozerskoe field which is located onshore Kolguyev Island in the Kolguyev Terrace in the East Barents Basin. Urals acquired 100% of Arcticneft in July 2005. The E&P License is valid till the end of December 2067 and in October 2015 the Company expanded the boundaries of the license area and increased the reserves base. The Central part of the Peschanoozerskoe is operated by Arctic Oil Company Limited (ANK) which has an R&D license for the development of the central part of the oil field. In 2016 this central part of Peschanoozerskoye was acquired by Urals by purchase of ANK.

The field area is covered by high resolution 3D data in the central area with a good grid of 2D data covering remaining parts. Blackwatch found that the structure mapping was reasonably robust but did not investigate the time to depth conversion that is adequately constrained by well tops. A large number of maps (structure isopach and net pay) were loaded and geo-rectified on Kingdom workstation in order to estimate the Gross Rock Volume (GRV).  A range of tabulated input values were used for probabilistic determination using crystal ball. As a result, Blackwatch was able to replicate Ural's in-house estimates which are a significant uplift on Miller and Lents 2014 assessment. The deeper "reefal" play and associated anomalies is not well defined but provides significant upside resource potential. Further G&G studies are recommended and required to identify optimal drilling locations to test this play.

The oil was probably sourced from mature Lower to Middle Triassic mudstone in the deeper part of the South Barents Basin north of the area of interest. Petroleum generated from Triassic mudstone is interpreted to have migrated up-dip to the field. The oil is a high quality light (46.7°API), low sulphur (0.075%), low paraffin crude that sells at a premium of $1 to 1.8/ bbls to Brent.

The primary objective reservoir interval comprises stacked Lower Triassic parallic - fluvial continental and shallow regressive) marine sandstones with secondary (as yet under-explored) potential in Permo- Carboniferous and Devonian reefal build-ups.  The Triassic sandstones (Charkabozh formation) are lithic-rich, but still with fair to good porosity ranging from 13-24%, and permeability ranging from tenths to nearly 200 millidarcies. However pay zones are thin with net pay ranging from 3-12 m. The sedimentary architecture of the reservoir was not reviewed in detail for this report but is probably complex, and in combination with thin zones is likely to result in low overall recovery.  However correlation of e-logs shows good lateral continuity of sand intervals cross the field area.

The oil is trapped in low amplitude anticlines but a combination of stratigraphic pinch-out and structure provides effective trapping. The area contains abundant and excellent Mesozoic shale seals

The Peschanoozerskoye has flexible facilities and infrastructure. The Oil treatment facility has a capacity of 2,205 bopd, export crude oil storage capacity of 555,000 bbl and oil product storage capacity of 50,000 bbl (including oil storage capacity of newly acquired assets). Existing storage facilities allow accumulation of production year-round. There are two sea loading points which provide 100% export capability. They are located directly off the coast and adjacent to the field's crude oil tank farm which allows Oil tankers up to 50,000 ton deadweight. The field also has an oil refining unit with c.440 bopd capacity and produces diesel, fuel oil and straight run gasoline mostly for own needs and local sales points.

The company owns Well Work Service Units of type APRS 40 with rated capacity up to 40 tonnes and type UPA 60/80 with rated capacity up to 80 tonnes in addition to a Russian-made drilling rig (type Uralmash-3D-76). This drilling rig can handle a maximum depth of 5,000 m and thus provides options for exploration and production well drilling. The rig capacity is up to 260 tonnes and its located on the field. The company also owns a Reservoir Pressure Maintenance System which utilises water from an aquifer system of Middle Triassic deposits containing high-pressure waters. water wells are drilled to a depth of 1,300-1,400 m and are equipped with submersible pumps.

In 2016 there were a total of 26 producing wells with a production capacity of approximately 1400 bopd. Most wells are assisted by artificial lift. A programme of well intervention and installation of pumps is planned to maintain production.

III) BVN Oil - Babaevsky

BVN oil LLC incorporated in 2013 in order to develop the Babaevsky license area is located within well-known the Velhiu-Tebukskogo petroleum district Timan-Pechora oil and gas province. Urals Energy acquired 100% of BVN oil in November 2015. BVN holds two licences; one for exploration (including outside the currently defined field) the other for exploitation. The concessions are conveniently located with respect to export routes to refineries and Europe.

There is no current production but an exploration well drilled in 2013 flowed oil at 130bopd. Previous drilling indicates an approximately 50m gross oil column (1815-1865 OWC) but there is significant uncertainty in the data. Offset fields believed to host oil in comparable reservoirs produce 15-20tons /day.  Urals are confident this could be increased to 40-60tons/day after fracture stimulation. The permeability of the formation is not known at present or whether the matrix is naturally fractured. Primary objective is the terrigenous Upper Devonian (Yaranskii (layer Iv), Jier (layers 1a, 1av) and Timan (layer A2). However, there may be additional oil-bearing zones above the Domanic or even within it. The proposed work programme includes 30 Km2 of 3D seismic data acquisition and interpretation and four exploratory wells with a design depth of 2,080 m, to horizon - D3jar (Jherei). The 2017 work programme included seismic re-interpretation to evaluate possible license area extensions.

Available seismic data is of fair quality and was seen to confirm a structure is present.  However Blackwatch did not carry out an independent interpretation and did not evaluate time to depth conversion.  There is clearly significant uncertainty in the trap size and faulting.  This uncertainty will be reduced with the exploration programme proposed by Urals Energy.

Blackwatch loaded 2D seismic data and images of the depth closures (which were georectified) to Kingdom workstation in order to estimate volumes. We also accessed reports detailing the input parameters (porosity, saturation, formation volume factor) for input into crystal ball3. As noted by Urals, the geological data available in this area is very limited and therefore these parameters have been compiled mainly from nearby analogue accumulations.  There is also very significant uncertainty in the recovery factor that may be achieved. There is clearly a working petroleum system in the licensed area and the possibility of significant upside potential.

IV) RK-Oil - Ordymsky

RK oil LLC incorporated in 2014 in order to develop the Ordymsky license area which is located within the well-known the Omra-Soyvinskomu petroleum district Timan-Pechora oil and gas province. Ordymskiy is a large licensed area (444.7Km2), with good road accessibility and a rail link only 3Km to the North. A variety of export routes to refineries and the European market are potentially available. Urals Energy acquired RK oil (100%) the Licence holder in 2014.  The concession is valid to 2040 with the initial assessment of 3C resources stated as 162.4 million tons STOIIP, 35.9million tons (266 million bbls) recoverable. Various seismic surveys were acquired between 1975 and 1995 (giving a seismic coverage of approximately 0.94 line km per km2). A detailed electromagnetic survey conducted in 2000. This supported leads identified by the seismic data and RK went ahead and drilled a well South Ordymsojvinskoj. Blackwatch loaded the 2D data into Kingdom workstation and found it good quality with indications of flat spots and DHIs. However, the fault pattern is less clear.  Blackwatch did not carry out any independent geophysical interpretation and cannot comment on the time to depth conversion used by RK to generate maps. In total 34 wells have been drilled in the concession area.

South Ordymsojvinskoj-1 was drilled in 2001 to a TD of 750 m and penetrated Tournaisian carbonates that flowed oil at a rate of 0.79m3 /day with a flowing pressure of 60-70 atms. This oil was a sweet light (0.897 sg) crude.  Formation temperature is not known.  In 2015 seismic was re-processed to further evaluate the deep potential around South Omrinskaja and Ordymskaja. In total 4 interesting structures have been identified with stratigraphic potential recognized in both reefal build-up and reef flank plays. Build-ups are interpreted to have up to 400m vertical relief and extend up to 15Km with areal closure around 40 sq km in the maximum case.

A well was spudded in April 2017 but Urals terminated operations due to unsatisfactory performance by the contractor. Present status is not known.

Reports show that the pay zones are thin. Prospective resource base for Ordymskiy is recognized in Tournaisian (Carboniferous), Fammenian and Frasnian (Upper Devonian) and Eifelian (Middle Devonian). The projected reservoir zones are prognosed in:

  • С1t
  • D3fm
  • D3dzr, 1-а and 1-b ( D3f1)
  • D3jar, 1-v (B-2 bundle + B-3)
  • D2ef. Stratum III

Blackwatch inspected and measured the mapped structures provided by Urals. Using the available seismic data, which is of fair to good quality, a reasonable range of minimum and maximum GRVs (P10-P90) was used to estimate a range of possible outcomes.

Based on reports provided input parameters were found satisfactory and were adopted to estimate a reasonable range of input parameters. Blackwatch has not carried out independent petrophysical analysis but consider that porosity is well constrained by core information but that there is significant uncertainty in estimation of N/G ratio, hydrocarbon saturation, FVF and especially projected recovery factors.

Blackwatch attempted to capture this uncertainty within the P10-P90 range of input parameters. A further uncertainty is the physical character of the hydrocarbons with low gravity and high viscosity possible at shallow levels. In-depth geophysical and geological studies are recommended to further refine drilling locations and resource potential.

V) Blackwatch Findings

We have undertaken a review/audit of the data provided and the technical work carried out by Urals, its advisors and third party consultants and we have carried out independent estimates of reserves, and prospective resources as summarised in Tables ES-1.

Table ES-1 Blackwatch Reserves and Resources Estimates for Urals Assets

  Original Recoverable Reserves Prior to Production (MMSTB) Cumulative Production as of 31/12/2018 (MMSTB) Gross Remaining Reserves as of 31/12/2017 Urals Interest in the Licence Net attributable Remaining Reserves as of 31/12/2017 Operator
  Proved (1P) Proved +Probable (2P) Proved +Probable +Possible (3P)   1P 2P 3P   1P 2P 3P  
Okruzhnoye Total 24.5 40.6 67.4 23.76 0.8 16.9 43.7 97.16% 0.73 16.37 42.41 Petrosakh
South Dagi Total 2.9 20.9 38.3 0.00 2.9 20.9 38.3 97.16% 2.82 20.32 37.25 Petrosakh
Okruzhnoye & South Dagi Combined 27.4 61.5 105.8 23.76 3.7 37.8 82.0 97.16% 3.55 36.69 79.66 Petrosakh
Babaevskiy Total 1.0 10.8 13.7 0.00 1.0 10.8 13.7 100% 1.00 10.80 13.66 BVN Oil
Peschanoozerskoye Total 58.7 76.8 96.3 17.85 40.8 59.0 78.4 100% 40.84 58.97 78.43 Articneft + ANK

 

  Gross Prospective Resources (MMSTB) as of 31/12/2017 Urals Interest in the Licence Net Attributable Prospective Resources (MMSTB) as of 31/12/2017 Risk Factor Operator
  Low Estimate (P90) Best Estimate (P50) High Estimate (P10) % Low Estimate Best Estimate High Estimate %
Ordymsky Total 124.7 178.0 256.4 100% 124.7 178.0 256.4 25% RK Oil

 

Part-2) Professional Qualifications

Blackwatch Petroleum Services Ltd (Blackwatch) is an independent provider of geological, petroleum engineering, well testing and drilling engineering services to the international petroleum industry. Blackwatch specialises in the modelling, estimation, assessment and evaluation of oil and gas assets.  Blackwatch was established in 1994 with offices in central London and Aberdeen and a multi-national / multi-disciplined staff base. As such, Blackwatch has acquired experience in most of the hydrocarbon producing provinces of the world. Blackwatch has performed work for a wide variety of clients, ranging from multi-national and state oil companies, small independents, investment banks, financial institutions, stock markets and governments. Blackwatch's client base includes ADCO, BP, Shell, ConocoPhillips, Exxon Mobil, ChevronTexaco, ENI, JNOC (renamed JOGMEC), GDF, Marathon, Merrill Lynch, EBRD, Norsk Hydro, Cairn Energy, CNR, Victoria Oil and Gas and many others.

Except for the provision of professional services on a fee basis, Blackwatch does not have any interest in or commercial arrangement with any persons employed by or acting for Urals.

This report has been prepared under the supervision of Radwan Hadi, and David Craik. Mr Hadi is a BSc graduate and was awarded an MSc in Chemical Engineering from the University of Bradford in 1979. He is Deputy Managing Director of Blackwatch and has over thirty-five years of experience in the international oil industry in the estimation, assessment, evaluation, exploration, development and management of hydrocarbon reserves and resources. Mr Craik is a BSC Geology Graduate from the University of Liverpool and was awarded an MSc in Sedimentology from the University of Reading in 1976. He is a Fellow of the Geological Society and a Member of the Petroleum Exploration Society of Great Britain (PESGB). He is an experienced petroleum explorer with over thirty-five years of experience in the international oil industry in the estimation, assessment and evaluation of hydrocarbon reserves working on assignments with oil majors such as BG, BP, Repsol and Sun as well as independent operators. Since 1996, he has worked as an independent geological consultant providing services to a wide range of upstream clients including Private Equity backed E & P start-ups and multi-national corporations in the UKCS and internationally. Blackwatch declares that to the best of its knowledge and belief, having taken all reasonable care to ensure that such is the case, the information contained herein is in accordance with the facts and does not omit anything likely to affect the import of such information.

 

Yours faithfully,

Radwan Hadi
Deputy Managing Director
Blackwatch Petroleum Services Limited

 

1Source: Urals Energy Website http://www.uralsenergy.com/content/Petrosakh/Petrosakh.asp

2Source: Urals Energy Website http://www.uralsenergy.com/content/Petrosakh/Petrosakh.asp

3Crystalball is a spreadsheet-based software suite for predictive modeling, forecasting, simulation and optimization. It's used by Blackwatch to carry out probabilistic hydrocarbon volumetric calculation. https://www.emerald-associates.com/software/oracle/oracle-crystal-ball/crystal-ball.html 

 

 

For further information, please contact:

Urals Energy Public Company Limited
Andrew Shrager, Chairman
Leonid Dyachenko, Chief Executive Officer
Tel: +7 495 795 0300, www.uralsenergy.com

Allenby Capital Limited, Nominated Adviser and Broker
Nick Naylor / Alex Brearley
Tel: +44 (0) 20 3328 5656, www.allenbycapital.com

 

Appendix

Glossary of Technical Terms

Reserves Categories:

(Source: http://www.spe.org/industry/docs/Petroleum_Resources_Management_System_2007.pdf - pages 28 & 29)

Proved reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.

Probable reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.

Possible reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves.

1P - Taken to be equivalent to Proved Reserves; denotes low estimate scenario of Reserves.

2P - Taken to be equivalent to the sum of Proved plus Probable Reserves; denotes best estimate scenario of Reserves.

3P - Taken to be equivalent to the sum of Proved plus Probable plus Possible Reserves; denotes high estimate scenario of reserves. 

Prospective Resources Categorization

Source: http://www.spe.org/industry/docs/Petroleum_Resources_Management_System_2007.pdf - pages 31, 39 & 37

Low (P90) resource: With respect to resource categorization, this is considered to be a conservative estimate of the quantity that will actually be recovered from the accumulation by a project. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

Best (P50) resource: With respect to resource categorization, this is considered to be the best estimate of the quantity that will actually be recovered from the accumulation by the project. It is the most realistic assessment of recoverable quantities if only a single result were reported. If probabilistic methods are used, there should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

High (P10) resource: With respect to resource categorization, this is considered to be an optimistic estimate of the quantity that will actually be recovered from an accumulation by a project. If probabilistic methods are used, there should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

Prospective Resources - those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

Remaining Reserves and Resources - those quantities of petroleum (of any category) which are estimated, as of a given date, to be recoverable after deducting actual petroleum quantities that are already produced.

 

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