Legal Proceedings Report • May 4, 2016
Legal Proceedings Report
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• 1 May 2016
Cyprus Stock Exchange
Nicosia
Attached hereto a CPR prepared by an independent Competent Person, Dunmore Consulting for Halamish structure in the Hatrurim License.
1st May 2016
Mr. Rami Kremien Gulliver Energy Ltd. Ginko Oil Exploration L.P. Zerach Oil & Gas Exploration L.P. 11, Menahem Begin Road Ramat Gan Israel
Mr. Eyal Shuker Israel Opportunity Energy Resources L.P. C.O. Cyprus Opportunity Energy Public Company Limited 2, Ben Gurion Street Israel
Dear Sirs
The undersigned independent Competent Person, registered by the Society of Petroleum Engineers (SPE) No 0357319, has developed the Competent Persons Report (CPR) attached and confirms that it is in accordance with the internationally recognized standards, definitions and guidelines set forth in the 2007 Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers (SPE) as stipulated by the Israel Securities Authority (ISA). In compliance with these standards the reader should note that no hydrocarbon volumes referenced in this CPR can be categorised at the time of writing as reserves. To assist the reader certain extracts of the PRMS and definitions are included at the end of this report.
Dunmore Consulting (DC or ourselves) has not been tasked with nor attempted to verify the mathematical correctness of any calculations executed by Ginko Oil Exploration L.P. or any third parties on its behalf and cited in this CPR.
This report has been prepared for the sole use of Gulliver Energy Ltd. ("Gulliver"), Ginko Oil Exploration L.P. ("Ginko") , Zerach Oil and Gas Exploration L.P. ("Zerach"), Israel Opportunity Energy Resources L.P. ("Israel Opportunity"), C.O. Cyprus Opportunity Energy Public Company Limited ("Cyprus Opportunity"), Ashtrom Group ("Ashtrom"), Dr. Eli Rozenberg Ltd. ("Rozenberg") (altogether henceforth "the partners") for filing with the Israel Securities Authority (ISA). In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purposes.
In accordance with your instructions to us we confirm that we:
are independent of Ginko, its directors, senior management and advisers;
will be remunerated by way of a time-based fee and not by way of a fee that is linked to the application, drilling success or value of the Company;
William Dunmore
Chairman, Dunmore Consulting
The content of this CPR and our estimates of potential resources, unrisked and risked values are based on seismic, exploration and test well data, and other geological data provided to us by Ginko. The Company provided us with all relevant and available data at the time of the drafting of this CPR. We have accepted, without independent verification, the accuracy and completeness of this data. The key sources for this work were a Geophysical Study of Halamish-1 prepared for Ginko Oil Exploration L.P. by Yuval Ben-Gai dated February 2016 and a Petrophysical Analysis of Halamish-1 and Halamish Deep-1 prepared by Opus 28 Limited in November 2014. These are both high quality studies by experienced professionals in their fields.
As part of our work we did not undertake a site visit to inspect the Company's exploration asset, as we did not consider that such an inspection would reveal information or data that would be material in the preparation of this CPR.
All interpretations and conclusions presented herein are opinions based on inferences from geological, geophysical, engineering or other data. The report represents Dunmore Consulting's best professional judgement and should not be considered a guarantee of results. Our liability is limited solely to the Company as set out in the letter of engagement.
Dunmore Consulting have not conducted any legal due diligence as to the Company's title to the properties, hydrocarbons, or revenues discussed in this CPR; nor whether or not the various production and exploration contracts, licences or permits have been properly granted or accepted by the relevant authorities.
Dunmore Consulting provides no warranty as to the veracity of the contents of this report. Dunmore Consulting has undertaken this work in good faith for the sole purposes stated above however any party wishing to take further interest in the licence should carry out its own due diligence.
Dunmore Consulting is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Those involved in this report were:
Mr William John Dunmore has a B.Sc in Physics/Chemistry from University College London (1969-72) and a M.Sc. in Petroleum Reservoir Engineering from Imperial College London (1976-77). He has been constantly been engaged in multiple aspects of the oil industry from exploration to development and production since 1972. He is qualified in reserves estimation and classification, petrophysics and audit techniques using both deterministic and probabilistic methods and economic analysis. He has been an independent petroleum engineering consultant since 1986 with particular emphasis on reserves assessment and commerciality since 1992. He has been a full and active member of the SPE since 1976.
| Preamble6 | |||||
|---|---|---|---|---|---|
| 1. | Legal Overview6 | ||||
| 1.1. | Licence Description6 | ||||
| 1.2. | Appointment of Operator6 | ||||
| 2. | Geological Overview 6 | ||||
| 3. | Exploration History 7 | ||||
| 4. | Resources and Reserves7 | ||||
| 4.1. | Contingent Resources7 | ||||
| 4.2. | Reserve and Resource statement9 | ||||
| 4.3. | Reconciliation with previous statements9 | ||||
| 4.4. | Statement regarding visit to property 9 | ||||
| 4.5. | Production Plans for Proved and Probable Resources 9 | ||||
| 4.6. | Historic Production and Expenditure9 | ||||
| 4.7. | Infrastructure9 | ||||
| 4.8. | Maps Plans and Diagrams10 | ||||
| 4.9. | Special Factors 12 | ||||
| 4.10. | Geophysical and Petrophysical Analysis13 | ||||
| 4.10.1. | Geophysical Summary13 | ||||
| 4.10.2. | Seismic interpretation13 | ||||
| 4.10.3. | Discussion and Conclusions 13 | ||||
| 4.11. | Petrophysical Summary including well testing and oil recovery 13 | ||||
| 4.11.1. | Lithology and Geological Zonation14 | ||||
| 4.11.2. | Clay Volume (VClay)14 | ||||
| 4.11.3. | Effective Porosity (PhiE)14 | ||||
| 4.11.4. | Water Saturation (Sw)15 | ||||
| 4.11.5. | Cut offs15 | ||||
| 4.11.6. | Lithology and Geological Zonation16 | ||||
| 4.11.7. | Clay Volume (VClay)16 | ||||
| 4.11.8. | Effective Porosity (PhiE)16 | ||||
| 4.11.9. | Water Saturation17 | ||||
| 4.11.10. | Permeability & Testing17 | ||||
| 4.11.11. | Hydrocarbon Contacts 17 | ||||
| 4.11.12. | Summary Results & Conclusions18 | ||||
| Appendix 1 - Glossary & Abbreviations 19 | |||||
| Appendix 2 - Extracts from Petroleum Resources Management System (PRMS)20 |
This format of this document matches that recommended by ESMA (European Securities and Markets Authority). This is the first CPR to be released by Ginko concerning this property.
The oil & gas exploration "licence "403/Hatrurim" was granted to the partners by the Israeli Oil Commissioner on the 27 th of October 2015 for a period of 3 years.
The holdings in the license are the following:
Ginko 28.75%, Zerach 38.75%, Israel Opportunity 25%, Cyprus Opportunity 5%, Ashtrom 10%, Rozenberg 2.5%.
The license is located west of the Dead Sea. The licence license area is 94.2 km2. The major outstanding work commitment in the exploration licence term is to drill the Halamish exploration well, with drilling commencing no later than 1st November 2017.
The partners listed above have signed a Memorandum of Understanding (MoU) designating Ginko as the operator of the licence.
The block is located to the west of the Dead Sea in eastern Israel. The Dead Sea sits in what is referred to as the Jordan Valley rift system. The west side of the valley is part of the African plate and the east side is part of the Arabian plate. These two plates are sliding past each other, and in a few places they are also pulling apart from one another. The result of this is a rift valley. As the plates have pulled apart, the area between the plates has subsided resulting in a sediment filled depression well below the surface of the nearby Mediterranean Sea. Both Jurassic and Triassic sequences consist of a stacked sequence of carbonates with minor clastics and claystones.
The geological system in general comprises clastic lithologies suggestive of a shallow marine environment, with fore-reef conditions prevailing during short periods. The available lithology descriptions from the wells are consistent with this interpretation. The upper intervals of the Zohar Formation (Middle Jurassic) are present in both wells analysed and correlate well between the two. While gas was found in the nearby Zohar Field in the Jurassic section, the same formations in the subject wells do not contain any significant calculated hydrocarbons. Oil was discovered and produced in the neighbouring Zuk Tamrur wells from the Triassic section and this section was penetrated by the Halamish Deep-1 well with a calculated net pay of 17 m.
The Hatrurim block is currently held under an exploration license granted to partners led by Ginko Oil Exploration L.P. The Halamish-1 well was drilled by the Israel National Oil Company (INOC) in 1962. It was located southeast of the newly discovered Zohar Gas Field (Fig. 1) and penetrated the upper Triassic (Mohilla Formation) down to a TD of 1670 m (kb). In the mid-1990's the area was operated by Avner Oil and Gas that conducted seismic survey across the old well in 1994. Avner deepened the hole in 1995 to a TD of 2210 m (kb) into the Lower Triassic Raaf Formation. A net pay of 17m out of a gross interval of 426m was found in the Triassic section from the Saharonim to the Raaf Formations (Opus 28, 2014). Avner Oil and Gas contracted Schlumberger to conduct a VSP study in the well that resulted in an E-W cross section. The nearby Shalhevet-1 well was drilled by Naphta in 1993. The well reached a TD of 1206 m (kb) in the Jurassic Sherif Formation.
| Halamish-1 | Halamish Deep-1 | Shalhevet-1 | ||
|---|---|---|---|---|
| Operator | Israeli NOC | Avner Oil & Gas | Naptha Israel | |
| Year | 1962 | 1995 | 1993 | |
| Result | P&A, Dry Hole | P&A, Oil Discovery | P&A, Dry Hole | |
| Mud type | WBM | WBM | WBM | |
| Hole size | 12.25" hole at TD. | 4" hole at TD. | 6 1/8" hole at TD. | |
| Deviation | Vertical | Vertical | Vertical |
The relevant well data used for petrophysical and geological analysis are as follows:
All the resources shown have been estimated using probabilistic methods. Once a discovery is made and development is undertaken, the probability that the recoverable volumes will equal or exceed the unrisked estimated amounts is 90% for the low estimate (1C), 50% for the best estimate (2C), and 10% for the high estimate (3C). As recommended in the PRMS and tabulated below, the low, best, and high estimate resources have been aggregated by arithmetic summation; therefore, these totals may be considered conservative as they do not include the portfolio effect that might result from statistical aggregation.
Input parameters for the calculation of the resources shown were derived from the geophysical, petrophysical and engineering studies discussed later in this report. Low, most likely and high values of each parameter were assigned and then combined using statistical or 'Monte Carlo' methods to estimate the range of volumes both in place and recoverable.
The contingent resources are those quantities of petroleum we estimate to be potentially recoverable from the Halamish discovery. However as there is as yet no project for commercial development of these volumes due to one or more contingencies we have classified them as contingent resources at this time rather than reserves.
The contingent resources shown in this report are subclassified as development unclarified1 and are contingent upon generation and approval of a development plan, project sanctioning, and a commercial viable forecast case. If these contingencies are successfully addressed, some portion of the contingent resources estimated in this report may be reclassified as reserves; our estimates have not been risked to account for the possibility that the contingencies are not successfully addressed. Because of the lack of commercial data given the early stage of development of this project, we did not perform an economic analysis on these resources; as such, the economic status of these resources is undetermined. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
The petrophysical input parameter ranges for the probabilistic estimated ultimate recovery (EUR) for the Halamish structure are as shown below by interval:
| Saharonim | 1785.0 - 1999.0m | Gevanim 1999.0 - 2060.0m | |||||
|---|---|---|---|---|---|---|---|
| Parameters | units | Low | Best | High | Low | Best | High |
| Net Thickness | m | 2.44 | 3.05 | 3.97 | 2.32 | 2.90 | 3.77 |
| Porosity | % | 4.00% | 5.20% | 7.00% | 9.28% | 11.60% | 15.08% |
| Hyd Saturation | % | 51.60% | 64.50% | 83.85% | 45.92% | 57.40% | 74.62% |
| FVF | v/v | 1.30 | 1.15 | 1.10 | 1.30 | 1.15 | 1.10 |
| Rec Factor | % | 10.0% | 12.5% | 16.3% | 12.0% | 15.0% | 19.5% |
| Gevanim 2073.0 - 2193.6m | Ra'af 2193.6 - 2210.8m | ||||||
| Parameters | units | Low | Best | High | Low | Best | High |
| Net Thickness | m | 7.31 | 9.14 | 11.88 | 1.83 | 2.29 | 2.98 |
| Porosity | % | 4.00% | 9.90% | 12.87% | 4.00% | 8.00% | 12.00% |
| Hyd Saturation | % | 54.16% | 67.70% | 80.00% | 64.88% | 81.10% | 85.00% |
| FVF | v/v | 1.30 | 1.15 | 1.10 | 1.30 | 1.15 | 1.10 |
| Rec Factor | % | 12.0% | 15.0% | 19.5% | 12.0% | 15.0% | 19.5% |
We believe that these ranges maybe conservative as the evaluator has acknowledged that the thin spikes of higher hydrocarbon saturation may well be an underestimate of the true saturation due to the lack of log resolution in such thin beds, the resistivity tools in particular are prone to this effect.
1 Defined by PRMS as "a discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay".
The area ranges input for the calculation are as follows:
| Sq. kms. | Low | Best | High |
|---|---|---|---|
| Halamish | 3.14 | 8.00 | 15.00 |
The volumes shown below (millions of barrels) for The Halamish structure are classified to be Contingent Resources as the Halamish Deep-1 well recovered oil from the Triassic zones tested but there is no firm agreed plan to develop these volumes at this date.
| Gross (100%) Contingent Resources | |||||
|---|---|---|---|---|---|
| Halamish | |||||
| MMB | Low (1C) | Best (2C) | High (3C) | ||
| EUR | 4.001 | 6.861 | 11.198 |
This is the first CPR statement to be released on this License.
As part of our work we did not undertake a site visit as we did not consider that such an inspection would reveal information or data that would be material in the preparation of this CPR.
The Company does not have any development plans for this property at this time. The commercial development and production of the "Halamish" oil resources will depend on regulatory approval, global oil prices and the results of exploration drilling in the area.
Not applicable to an exploration block.
Not applicable to an exploration block.
Fig. 1. A general map showing the licence outline and the Dead Sea
Fig. 2. Top Judea map of the Halamish area.
Fig. 3. Top Zohar map, based on ispaching down from the Top Judea map
Nothing to report.
The Company commissioned recently a geophysical study from Yuval Ben-Gai (February 2016). This study aimed at reprocessing the seismic lines acquired across the Halamish1 well in 1994 as a key to structural interpretation. The reprocessing, conducted by the Geophysical Institute of Israel (GII) in 2016 resulted in improvement of the seismic image in the Jurassic level, yet no clear events can be seen at the target level in the Triassic. The Jurassic section as interpreted confirms the structural setting as can be inferred from correlation of wells in the area, which also suggests that the Triassic section fairly conforms to the Jurassic section. Results of a VSP study performed in the deep well and successfully imaged the Triassic target zone, cannot be confirmed by the reprocessed lines due to the poor energy penetration.
The seismic data available for this study included the 2D seismic lines across the Halamish-1 well, the lines across the Zuk Tamrur wells and the VSP in Halamish-1 well. The lack of velocity information away from the well does not allow a proper depth conversion. Certainly, stacking velocities are not a reliable source in this case. It is assumed that the time sections (corrected to MSL datum) are a close representation of the depth relations.
Overall data quality was moderate and much processing was required to achieve any useable sections. The study concluded that structural closure may be due to the faults that were inferred by the seismic interpretation. These may show a block bounded to the west and the east by faults that are 4-5 apart and in the north to south by faults 2-3 km apart. These figures may suggest an area of 8 to 15 sq.km that may be considered as the best and high cases for volumetric estimation.
A standard petrophysical methodology was used by Opus 28 Limited in November 2014, which comprised three steps for each geological zone:
The intervals analysed were the Jurassic in Halamish-1, and the Triassic in Halamish Deep-1. Ages, tops and reservoir zones were taken from the Comp Log and well reports provided. The petrophysical zones used in the analysis were based on consistent lithological units as interpreted in each well. The geological system in general comprises clastic lithologies suggestive of a shallow marine environment, with fore-reef conditions prevailing during short periods. The available lithology descriptions from the wells are consistent with this interpretation, as indicated by selected comments below.
| Formation | Coates et al. | Halamish | ||
|---|---|---|---|---|
| Zohar (Jurassic) | Detrital and argillaceous Lst with shale intercalations. Mostly fore-reef. |
More complex mineralogy suggested including more dolomitic, some gypsum, pyrite and chert Veins and fractures in Cores 2 and 3, sometimes |
||
| Sherif | Shale, marl and Lst with varying thickness Sst beds. Very shallow marine. |
abundant Rock builders in Lst in Zone T, including algae and bryazoa Karst and/or cavings in interbedded Lst 1320-1340m |
||
| Daya | Lst, sandy Lst, dolomite and some sandy marl. Marine hemi-pelagic |
|||
| Mohilla (Triassic) |
Dolomitic, gypsiferous, interbedded anhydrite Magmatic sills |
Knowledge of the lithology is particularly important in mixed carbonate sequences because it is difficult to discriminate between dolomite and limestone-shale sequences on the basis of logs alone. In this report, the lithology log from the Comp Log was digitised for the three wells and used in combination with a number of crossplots, including the Density/Neutron and Density/Sonic plots, to discriminate log points falling between dolomite, limestone, shale and marl. The VClay estimates were made iteratively for each zone, based on the Gamma Ray and the assumed lithology.
The second step of the petrophysical workflow was to calculate the effective porosity. This involves deriving total porosity (PhiT) from the neutron, density and sonic curves and then backing out the PhiE by subtracting the clay bound porosity using VClay. The calculation of PhiT is very sensitive to variations in matrix mineralogy. There is a 5% difference in grain (matrix) density between limestone and dolomite, so knowledge of the lithology is therefore important in mixed carbonate sequences.
In this assessment, porosity estimates were made iteratively for each zone, comparing all available approaches including crossplots using all of the density, neutron and sonic porosity methods. Lithology was estimated using both multi-mineral analysis and comparison with SP and lithology tracks. The iterative approach was required because there are some very extreme log responses recorded in all 3 wells (relatively low porosity limestones with some apparently very high porosity units) which are not well dealt with by any single methodological approach. The principle approach used here was multi-mineral estimation of lithology to derive the grain density for the density porosity method; and the sonic method was used in cases of bad hole, using interpreted matrix parameters.
The geological sequence and drilling parameters was suited to using the standard Archie equation. The input parameters were as follows:
| Parameter | Value | Comment | |
|---|---|---|---|
| PhiE | Porosity | As above section | |
| Rt | True Resistivity | Halamish: LLD Halamish Deep: LLD and ILD |
Halamish Deep: LLD used in preference but only ILD in bottom hole and gap above log run 3 |
| Rw | Formation water resistivity |
Halamish: 0.1 @60°F Halamish Deep: 0.08 @60°F |
Jurassic Rw came from clear Rwapp in clean Jurassic intervals. |
| Temp | Temperature gradient | T = 70 + Measured Depth * 0.043 degrees F |
Common gradient used for all wells, based on scan data |
| m | Cementation Exponent | Default = 2 | No data available |
| n | Saturation Exponent | Default = 2 | No data available |
| a | Tortuosity factor | Default = 1 | No data available |
Formation water samples were obtained from the Halamish Deep tests and the range measured seems to be asymptotic to around 125,000 ppm NaCl inferring that this is the likely level of pure formation water salinity.
A porosity cut off of 4% was used throughout. No core data was available to support this, but the author's experience of similar carbonate sequences elsewhere suggests that this is the minimum porosity needed for net reservoir.
In carbonate sequences, a porosity cut off can be a very poor indicator of potential pay zones as porosity and permeability are not necessarily correlated. To address this, in addition to the usual V Clay, PhiE and Sw cut offs, an SP cut off was also used for the calculation of pay in the Halamish Deep-1 well. The SP log in this well appears to be a good and sensitive indicator of the presence of permeable zones. The well was drilled with a fairly fresh mud and deflections were measured wherever permeable beds (which contained higher salinity formation waters) were penetrated. As a result of this approach, we can be reasonably confident that the pay intervals calculated are likely to have some degree of permeability and so should produce hydrocarbons on test.
Reservoir and pay intervals were determined on the basis of the following cutoffs:
| Halamish-1 | Halamish Deep-1 | |
|---|---|---|
| V Clay | 0.4 | 0.4 |
| PhiE | 0.04 | 0.04 |
| Sw | 0.6 | 0.6 |
| SP | -7/-25 |
The boreholes are far from regular and poor hole conditions are typically associated with DRHO errors. However, there are consistent "high porosity" curve departures on the density, neutron and sonic logs of three different generations in both wells. This strongly indicates that the zones are associated with real, high porosity, intervals as opposed to repeated tool errors.
The very limited geological information available suggests that these zones may be related to karstic erosion; caving of reefs; and/or veins or fractures (possibly associated with the emplaced sills). The Halamish cores do cover some "high porosity" zones but the descriptions do not mention this and do not help with identifying the cause of the readings. Taken together, significant uncertainty remains in the determined lithologies.
A reasonable estimate of the Clay Volume has been made throughout the target intervals but there many intervals in which there is no single interpretation of lithologies, particularly in dolomite – limestone – shale – marl interbeds. The "high porosity" intervals in both wells can be associated with high or low GR. The intervals with high GR do not calculate as reservoir because they fail the VClay cutoff. If these intervals are associated with fractures and veining, it is possible that the high GR is due to mineralisation and not shale content, in which case reservoir intervals would have been missed.
As described above, porosity estimates were made iteratively for each zone, comparing all available approaches. Porosities were also compared to the permeability as indicated by SP, shows and tested intervals. In most intervals, alternative methods were largely consistent but this was not always the case. The calculated porosities are representative of tight carbonate formations and are broadly consistent with the reported results from Coates et al. (1963). However, no core analyses were available from these or offset wells to validate the results. The indicated Drho errors imply that density and neutron porosities are commonly incorrect due to tool limitations. In conclusion, significant uncertainty remains in the porosity estimates.
Aside from the uncertainty in the porosity estimates, the accuracy of the water saturation calculations depend on six other parameters as described above in the Petrophysical Approach. Rt, the true resistivity was assumed to be the available deep resistivity curve. LLD was used over ILD were possible, due to its higher vertical resolution. There are no obvious data problems with curves other than noted in the Petrophysical Approach. Rw, taken from Rwapp calculations in the Jurassic and from salinity measurements of water produced on test from the Triassic in Halamish Deep-1.
The Archie parameters a, m and n are generally held to be heterogeneous in carbonates. In particular, the saturation exponent (n) is dependent on various characteristics of the rock including texture or grain pattern, pore type and distribution, and wettability. Wettability is thought to be the main factor affecting the saturation exponent. Water saturations are very sensitive to these parameters and values for individual wells should be derived from special core data. No data was available in this case to inform a choice other than the conventional values of 1, 2 and 2 respectively for a, m and n. This is a significant source of uncertainty in the Sw calculations. The main validation of the Sw calculations was through comparison of the SP cure and the test results. The tests flowed a mix of water and oil, indicating that the reservoirs are oil bearing but not fully saturated, consistent with the calculated saturations. The location of the tests and the test results consistently coincide with good deflections in the SP log.
The SP log in this well appears to be a good and sensitive indicator of the presence of permeable zones. The well was drilled with a fairly fresh mud and deflections were measured wherever permeable beds (which contained higher salinity formation waters) were penetrated.
Extensive swabbing tests were made in the Halamish Deep-1 well and were reported in detail in the May 1998 Well Completion report. These were in the Ra'af, Gevanim and Saharonim formations. During the testing operations, the formations were treated with HCL and HF acids and with diesel injection. A sand fracture treatment was also applied to the Gevanim formation in order to increase permeability. We have examined the results of these swabbing operations. A pressure build-up test was performed after fracturing treatment. The well, was production tested for a few days after fracturing, and was shut in for the subject build-up test. The pressure data was analysed by Garb & Associates. The results of the data analysis were as follows: the most effective permeability to oil value was approximately 1.0 md. The most likely hydraulically fracture half-length value was 35 feet, and the estimated initial reservoir pressure of 2628psig. The oil recovered from the tests was in the range of 22-37° API.
No contacts were seen in the log analysis.
Contingent Resources – are defined by PRMS to be those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.
"Development Unclarified" Project Maturity Sub-Class – PRMS classification of a discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.
FVF (Formation Volume Factor) - the ratio between the liquid volume at reservoir conditions, to its volume at standard conditions.
Hyd (Hydrocarbon) Saturation - the ratio between the oil volume to the volume of voids (frac. or %).
MMB - Million Barrels of Oil
Net thickness - thickness of the reservoir which contributes to production (length units).
Porosity - the ratio between the volume of rock voids to its bulk volume (frac. or % ).
Rec (Recovery) Factor - the ratio of volume of oil produced, to the volume of oil in the reservoir at standard conditions. (frac. or %).
Sq kms – Square kilometers
Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth's crust. Resource assessments estimate total quantities in known and yet-to-bediscovered accumulations; resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework.
International efforts to standardize the definitions of petroleum resources and how they are estimated began in the 1930s. Early guidance focused on Proved Reserves. Building on work initiated by the Society of Petroleum Evaluation Engineers (SPEE), SPE published definitions for all Reserves categories in 1987. In the same year, the World Petroleum Council (WPC, then known as the World Petroleum Congress), working independently, published Reserves definitions that were strikingly similar. In 1997, the two organizations jointly released a single set of definitions for Reserves that could be used worldwide. In 2000, the American Association of Petroleum Geologists (AAPG), SPE, and WPC jointly developed a classification system for all petroleum resources. This was followed by additional supporting documents: supplemental application evaluation guidelines (2001) and a glossary of terms utilized in resources definitions (2005). SPE also published standards for estimating and auditing reserves information (revised 2007).
These definitions and the related classification system are now in common use internationally within the petroleum industry. They provide a measure of comparability and reduce the subjective nature of resources estimation. However, the technologies employed in petroleum exploration, development, production, and processing continue to evolve and improve. The SPE Oil and Gas Reserves Committee works closely with other organizations to maintain the definitions and issues periodic revisions to keep current with evolving technologies and changing commercial opportunities.
This document consolidates, builds on, and replaces guidance previously contained in the 1997 Petroleum Reserves Definitions, the 2000 Petroleum Resources Classification and Definitions publications, and the 2001 "Guidelines for the Evaluation of Petroleum Reserves and Resources"; the latter document remains a valuable source of more detailed background information, and specific chapters are referenced herein. Appendix A is a consolidated glossary of terms used in resources evaluations and replaces those published in 2005.
These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that this document will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings.
It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein should be clearly identified. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements.
This SPE/WPC/AAPG/SPEE Petroleum Resources Management System document, including its Appendix, may be referred to by the abbreviated term "SPE-PRMS" with the caveat that the full title, including clear recognition of the co-sponsoring organizations, has been initially stated.
The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. These quantities are associated with development projects at various stages of design and implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical and commercial factors that impact the project's economic feasibility, its productive life, and its related cash flows.
Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon content could be greater than 50%.
The term "resources" as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth's crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered "conventional" or "unconventional."
Figure 1-1 is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.
The "Range of Uncertainty" reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the "Chance of Commerciality, that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification:
TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to "total resources").
DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.
PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage (see Production Measurement, section 3.2).
Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.
RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.
CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub- classified based on project maturity and/or characterized by their economic status.
UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.
PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.
UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).
In specialized areas, such as basin potential studies, alternative terminology has been used; the total resources may be referred to as Total Resource Base or Hydrocarbon Endowment. Total recoverable or EUR may be termed Basin Potential. The sum of Reserves, Contingent Resources, and Prospective Resources may be referred to as "remaining recoverable resources." When such terms are used, it is important that each classification component of the summation also be provided. Moreover, these quantities should not be aggregated without due consideration of the varying degrees of technical and commercial risk involved with their classification.
The horizontal axis in the Resources Classification (Figure 1.1) defines the range of uncertainty in estimates of the quantities of recoverable, or potentially recoverable, petroleum associated with a project. These estimates include both technical and commercial uncertainty components as follows:
Where commercial uncertainties are such that there is significant risk that the complete project (as initially defined) will not proceed, it is advised to create a separate project classified as Contingent Resources with an appropriate chance of commerciality.
The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution (see Deterministic and Probabilistic Methods, section 4.2).
When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that:
When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately (see Category Definitions and Guidelines, section 2.2.2).
These same approaches to describing uncertainty may be applied to Reserves, Contingent Resources, and Prospective Resources. While there may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production, it useful to consider the range of potentially recoverable quantities independently of such a risk or consideration of the resource class to which the quantities will be assigned.
Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental (risk-based) approach, the deterministic scenario (cumulative) approach, or probabilistic methods. (see "2001 Supplemental Guidelines," Chapter 2.5). In many cases, a combination of approaches is used.
Use of consistent terminology (Figure 1.1) promotes clarity in communication of evaluation results. For Reserves, the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must be viewed within context of, the complete resources classification system. While the categorization criteria are proposed specifically for Reserves, in most cases, they can be equally applied to Contingent and Prospective Resources conditional upon their satisfying the criteria for discovery and/or development.
For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. For Prospective Resources, the general cumulative terms low/best/high estimates still apply. No specific terms are defined for incremental quantities within Contingent and Prospective Resources.
Without new technical information, there should be no change in the distribution of technically recoverable volumes and their categorization boundaries when conditions are satisfied sufficiently to reclassify a project from Contingent Resources to Reserves. All evaluations require application of a consistent set of forecast conditions, including assumed future costs and prices, for both classification of projects and categorization of estimated quantities recovered by each project (see Commercial Evaluations, section 3.1).
Table III presents category definitions and provides guidelines designed to promote consistency in resource assessments. The following summarizes the definitions for each Reserves category in terms of both the deterministic incremental approach and scenario approach and also provides the probability criteria if probabilistic methods are applied.
• 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. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities
will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.
Based on additional data and updated interpretations that indicate increased certainty, portions of Possible and Probable Reserves may be re-categorized as Probable and Proved Reserves.
Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to report a single representative result, the "best estimate" is considered the most realistic assessment of recoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that under the deterministic incremental (riskbased) approach, discrete estimates are made for each category, and they should not be aggregated without due consideration of their associated risk (see "2001 Supplemental Guidelines," Chapter 2.5).
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