Circular 13/2024/TT-BCT regulating the classification and reporting of petroleum resources and reserves

CIRCULAR

Regulating the classification and reporting of petroleum resources and reserves

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Pursuant to the Law on Oil and Gas dated November 14, 2022;

Pursuant to Clause 7, Article 47 of the Government’s Decree No. 45/2023/ND-CP dated July 1, 2023 detailing a number of articles of the Law on Oil and Gas;

Pursuant to the Government’s Decree No. 96/2022/ND-CP dated November 29, 2022 defining the functions, tasks, powers and organizational structure of the Ministry of Industry and Trade; the Government’s Decree No. 105/2024/ND-CP dated August 1, 2024 amending and supplementing a number of articles of the Government’s Decree No. 96/2022/ND-CP dated November 29, 2022 defining the functions, tasks, powers and organizational structure of the Ministry of Industry and Trade and the Government's Decree No. 26/2018/ND-CP dated February 28, 2018 on the Charter on organization and operation of Vietnam Electricity;

At the request of the Director of the Oil and Gas and Coal Department,

The Minister of Industry and Trade promulgates the Circular regulating the classification and reporting of petroleum resources and reserves.

Chapter I

GENERAL PROVISIONS

Article 1. Scope of regulation and subjects of application

1. This Circular regulates the classification and reporting of petroleum resources and reserves when conducting petroleum activities within the land area, islands and sea areas of the Socialist Republic of Vietnam.  

2. This Circular applies to Vietnamese and foreign agencies, organizations and individuals involved in the classification and reporting of petroleum resources and reserves.

Article 2. Interpretation of terms

In this Circular, the following terms are understood as follows:

1. Produced petroleum (cumulative production) means the total quantity of petroleum that has been produced from a reservoir, or petroleum field, updated to the time of reporting.

2. Economic and technical conditions mean the economic and technical criteria that are carefully considered and justified for application at the time of reporting petroleum resources and reserves.

3. The category of resources that do not meet the conditions for commercial development (hereinafter referred to as the sub-commercial category) means discovered petroleum resources that are assessed as not meeting the economic and technical conditions for development.

4. The category of resources that meet the conditions for commercial development (hereinafter referred to as the commercial category) means discovered petroleum resources that are assessed as meeting the economic and technical conditions for development.

5. Petroleum resources means the total petroleum initially in-place that exists in natural accumulations.

6. Undiscovered Petroleum Resources mean the petroleum initially in-place that may exist in natural accumulations but have not been discovered by drilling.

7. Discovered Petroleum Resources mean the petroleum initially-in-place that exists in natural accumulations that have been discovered by drilling.

8. Productive layer means a set of petroleum-bearing reservoirs within a stratigraphic unit of a geological structure.

9. Play means a group of objects with potential to contain petroleum within a defined geological and geographical area, with the same source, reservoir, and seal conditions and characteristics.

10. Petroleum reservoir means a geological formation containing natural petroleum, characterized by porosity, permeability, fluid type, reservoir pressure, and separated from other reservoirs by barriers.

11. Reservoir testing means a hydrodynamic study conducted to fully determine parameters on reservoir hydrodynamic characteristics, hydrodynamic parameters, and assess the production potential of a part or the whole petroleum reservoir.

12. Potentially Recoverable means the quantity of petroleum estimated to be potentially recoverable from the petroleum initially in-place from sub-commercial or undiscovered accumulations.

Chapter II

CLASSIFICATION OF PETROLEUM RESOURCES AND RESERVES

Article 3. Basis for classification

1. The classification of petroleum resources and reserves shall be determined based on a combination of assessing the confidence level of geological, geophysical, and reservoir engineering; the production potential of the petroleum field; the technical and technological feasibility and economic efficiency of the project at the time of reporting petroleum resources and reserves.

2. The classification of petroleum resources and reserves shall comply with Article 4, Article 5 and Appendices IA, IB, IC issued together with this Circular.

Article 4. Classification of petroleum resources

Petroleum resources are classified into discovered petroleum resources and undiscovered petroleum resources.

1. Discovered petroleum resources: Depending on the technical and technological feasibility and economic efficiency according to the contractor's economic evaluation criteria at the time of reporting petroleum resources and reserves. Discovered petroleum resources are divided into commercial and sub-commercial, specifically:

a) Commercial category: The petroleum resources in the commercial category are classified into Proved (P1), Probable (P2), and Possible (P3) categories;

P1 is the quantity of petroleum estimated at a given time, corresponding to the highest level of confidence in the classification of petroleum resources. P1 must meet the following conditions: the petroleum reservoir is defined with a high level of confidence based on geological, geophysical, drilling, reservoir testing, and production data; the permeability, porosity, and petroleum saturation of the reservoir are confirmed by well logs and/or core samples; reservoir testing results and fluid samples allow for the determination of the ability to produce commercial oil and gas flow according to the contractor's economic evaluation criteria from at least one well;

P2 is the quantity of petroleum estimated at a given time, corresponding to a lower level of confidence than P1 in the classification of petroleum resources. P2 is determined to likely exist in the reservoirs based on geological and geophysical data but has not been verified by reservoir testing results or fluid samples;

P3 is the quantity of petroleum estimated at a given time, corresponding to a lower level of confidence than P2 in the classification of petroleum resources. P3 is determined when the quantity of petroleum may exist in reservoirs based on geological and geophysical data but is not reliable enough to be classified as P2;

b) Sub-commercial category: the petroleum resources in the sub-commercial category are classified into Proved (C1), Probable (C2), and Possible (C3) categories; The technical criteria for classifying C1, C2, and C3 are similar to P1, P2, and P3.

2. Sub-commercial petroleum resources are classified into the categories of predicted undiscovered petroleum resources (R1) and theoretically undiscovered petroleum resources (R2).

a) R1 is the quantity of petroleum estimated at a given time for prospective objects, reservoirs that have been mapped but have not yet been confirmed through drilling results;

b) R2 is the quantity of petroleum estimated at a given time for accumulations that are theoretically possible within a play with favorable geological conditions for petroleum accumulation but have not been mapped.

Article 5. Classification of petroleum reserves and potentially recoverable resources

1. Classification of petroleum reserves

Petroleum reserves are classified into Proved (P1), Probable (P2), and Possible (P3) categories.

a) P1 is the quantity of petroleum that can be economically recoverable, estimated at a given time with a high level of confidence, and are expected to be produced under the economic and technical conditions at the time of the estimate.

b) P2 is the quantity of petroleum that can be economically recoverable, such that the 2P (P1 + P2) reserves are economically viable, estimated at a given time with a moderate level of confidence, and are expected to be produced under the economic and technical conditions at the time of the estimate.

c) P3 is the quantity of petroleum that is economically recoverable, such that the 3P (P1 + P2 + P3) reserves are economically viable, estimated at a given time with a low level of confidence, and are expected to be produced under the economic and technical conditions at the time of the estimate.

2. Classification of potentially recoverable resources

Potentially recoverable resources are classified into C1, C2, and C3 categories for commercial category and R1 and R2 categories for sub-commercial category. The C1, C2, and C3 categories are estimated and assessed with high, moderate, and low levels of confidence, respectively, similar to the P1, P2, and P3 reserve categories. The R1 and R2 categories are estimated, forecasted, and assessed based on the corresponding R1 and R2 resource categories, with recovery factors determined using a similar principle based on the values of reservoirs, fields, areas, or adjacent basins.

Article 6. Boundaries of resource and reserve classification

1. The boundaries of resource and reserve classification shall be determined for each petroleum reservoir based on the principle of extrapolation consistent with the specific geological conditions, as prescribed in Appendix II issued together with this Circular.

2. The determination of classification boundaries and the distribution of petroleum reservoirs shall be based on specific documents and evidence. In case where an analogous method is applied, the contractor must provide data with origins and justify the applicability of such data to the field or reservoir being assessed to confirm the appropriateness of the chosen method and estimation parameters.

Article 7. Methods for assessing petroleum resources and reserves

1. The objects of petroleum resource and reserve assessment shall be petroleum reservoirs.

2. Petroleum resources and reserves shall be determined using the volumetric method (conventional or based on 3D geological modeling), similar density, material balance, geological synthesis and reservoir hydrodynamic dynamics (production simulation and production dynamics analysis), and other methods depending on the availability of data. Specifically:

a) Applicable methods include: the conventional volumetric method for all cases; 3D geological modeling for petroleum fields that have been developed or are under development; material balance and production dynamics analysis for petroleum fields are on production.

b) Other methods may be used depending on specific conditions, but their application must be justified.

3. The results estimated using different methods must be compared and reconciled.

4. In case of updating petroleum resources and reserves, the estimated results must be compared with previous results, and the reasons for any changes must be justified.

5. Petroleum resources and reserves, and their components, must be estimated separately for each product type, for each reservoir, for each reservoir rock type, and the feasibility of producing the estimated reserves must be assessed.

6. The parameters used in estimating petroleum resources and reserves must be in a consistent unit system. The figures for petroleum resources and reserves must be presented in the International System of Units (volume) as prescribed by the Law on Measurement, with reference to international petroleum industry practices.

Article 8. Estimation of petroleum resources and reserves

Based on the classification prescribed in Articles 4 and 5 of this Circular, petroleum resources and reserves shall be estimated as follows:

1. For discovered petroleum resources

a) Commercial category:

Petroleum resources and reserves shall be estimated for 1P (P1), 2P (P1 + P2), and 3P (P1 + P2 + P3) levels.

The 1P, 2P, and 3P shall serve as the basis for estimating the 1P, 2P, and 3P.

Petroleum reserves may be estimated using Deterministic or Probabilistic methods according to the following corresponding criteria:

- Deterministic method: 1P has boundaries, fluid properties, and reservoir characteristics that are specifically proven by geological, geophysical, and reservoir engineering, leading to the likelihood that the actual production will be greater than or equal to the estimated P1 value. Using this method, petroleum reserves are justified, assessed, and estimated based on the petroleum initially in-place corresponding to the appropriate recovery factor of the reservoir, field, or area, meeting the technical, technological, and economic requirements of the project at the time of reporting the resources and reserves.

- Probabilistic method: 1P has a probability of not less than 90% that the actual production will be greater than or equal to the estimated 1P value. 2P has a moderate level of confidence, with a probability of not less than 50% that the actual production will be greater than or equal to the estimated 2P value. 3P has a low level of confidence, with a probability of not less than 10% that the actual production will be greater than or equal to the estimated 3P value.

b) Sub-commercial category

Petroleum resources and potentially recoverable resources shall be estimated for 1C (C1), 2C (C1 + C2), and 3C (C1 + C2 + C3).

The method and estimation for 1C, 2C, and 3C shall be similar to those for 1P, 2P, and 3P.

c) Petroleum reserves of a field shall be updated in the Outline Development Plan (ODP) and its revisions; Early Development Plan (EDP) and its revisions; Field Development Plan (FDP) and its revisions; and updated Resource and Reserve Report (RAR).

d) Petroleum reserves of a field must be updated to reflect secondary and tertiary recovery methods such as infill drilling, exploitation of additional reservoirs, and application of Enhanced Oil Recovery (EOR) methods.

2. For undiscovered petroleum resources

These shall be estimated or forecasted for petroleum initially in-place and potentially recoverable resources, respectively (R1, R2), with low, moderate, and high levels corresponding to statistical probability confidence levels of 90%, 50%, and 10%, respectively. The recovery factor shall be determined using an analogous approach based on the geological characteristics and reservoir engineering data of reservoirs, fields, areas, or adjacent basins.

3. The methods for estimating petroleum resources and reserves are provided in Appendix II issued together with this Circular.

Article 9. Content of the petroleum resource and reserve report

1. The detailed content of the petroleum resource and reserve report shall be prepared according to the template provided in Appendix III issued together with this Circular, and shall consist of two parts:

a) Explanatory part;

b) Appendices, including tables, drawings, and other necessary documents.

2. The approval content includes: approval of petroleum initially in-place at the 2P (including P1 and P2) with a 50% probability, and recording of 2P petroleum reserves as the basis for developing and updating the field development and production plan, including solutions to improve and enhance the recovery factor.

3. For sub-commercial category and undiscovered petroleum resources, PetroVietnam shall record, compile, assess, and annually report to the Ministry of Industry and Trade to serve resource management and the development of future exploration, appraisal, and prediction strategies and plans.

4. Details of the approval and recording of petroleum resources and reserves are prescribed in Appendix IB issued together with this Circular.

5. Recording of updated petroleum resource and reserve reports

In updated petroleum resource and reserve reports as prescribed in Clause 5, Article 45 of the Law on Oil and Gas, in case where the total 2P petroleum initially in-place changes by less than 15% compared to the most recent approval, the contractor shall report to PetroVietnam for compilation.

Chapter III

IMPLEMENTATION PROVISIONS

Article 10. Transitional provisions

1. For petroleum resource and reserve reports that have been approved before the effective date of this Circular, contractors and state management authorities shall continue to implement them in accordance with the approved reports.

2. Petroleum resource and reserve reports that have been submitted to competent authorities before the effective date of this Circular and comply with the Law on Oil and Gas and the Government’s Decree No. 45/2023/ND-CP dated July 1, 2023 detailing a number of articles of the Law on Oil and Gas shall not be required to be resubmitted and shall be approved in accordance with the regulations in effect before the effective date of this Circular.

Article 11. Effect and implementation

1. This Circular takes effect on October 1, 2024 and replaces Circular No. 24/2020/TT-BCT dated September 18, 2020 of the Minister of Industry and Trade providing regulations on classification and formulation of reports on petroleum resources and reserves.

2. In case where the legal documents referred to in this Circular are amended, supplemented, or replaced, the new documents shall prevail.

3. During the implementation of this Circular, if there are any difficulties or problems, contractors and PetroVietnam shall report to the Ministry of Industry and Trade for consideration and resolution according to their competence./.

APPENDIX I

Classification diagram for petroleum resources and reserves

(Issued together with Circular No. 13/2024/TT-BCT dated August 8, 2024 of the Minister of Industry and Trade)

A. CLASSIFICATION DIAGRAM FOR PETROLEUM RESOURCES AND RESERVES

B. APPROVAL AND RECOGNITION OF PETROLEUM RESOURCES AND RESERVES

C. PROJECT MATURITY LEVEL DIAGRAM BASED ON PETROLEUM RESOURCES AND RESERVES

APPENDIX II

Determination of classification boundaries, justifying estimation parameters for petroleum resources and reserves, and recovery factor

(Issued together with Circular No. 13/2024/TT-BCT dated August 8, 2024 of the Minister of Industry and Trade)

I. DETERMINATION OF CLASSIFICATION BOUNDARIES, FOR PETROLEUM RESOURCES AND RESERVES

1. Determination of petroleum reservoirs

Depending on the geological characteristics, a petroleum reservoir (reservoir) shall be divided into two types: layered reservoir and massive reservoir.

1.1. A layered reservoir shall be determined by the following factors: top, base, sealing faults, structural closure, transform boundaries, stratigraphic pinch-out, or other types of boundaries. A layered reservoir may include multiple adjacent layers with similar reservoir properties, fluid type, reservoir pressure, and fluid contacts (layer set).

1.2. A massive reservoir shall be determined by its top, sealing faults, structural closure, impermeable boundaries, or other types of boundaries.

The reservoir shall be determined and justified based on structural maps, conventional seismic data, special seismic data, hydrodynamic data, information from reservoir testing, production, and other related data.

The classification of petroleum resources and reserves, and potential recovery of each reservoir type shall be conducted in accordance with Clauses 2, 3 and 4, Section I of this Appendix.

2. Vertical classification

The classification boundaries for petroleum resources and reserves shall be determined using the half-way method or other methods employing available geological, geophysical, and reservoir engineering data with clear theoretical basis and reasoning.

2.1. Proved (P1)

The P1 shall be determined as follows (Figure 1):

2.1.1 For oil or gas reservoirs: From the top of the oil or gas reservoir to the oil-water contact (OWC) or gas-water contact (GWC), or to the lowest point at which an oil or gas flow is obtained based on reservoir and well testing results, well log data, if the oil-water contact or gas-water contact has not been determined.

2.1.2 For oil reservoirs with a gas cap:

- For oil: From the oil-gas contact, or the highest point at which an oil or gas flow is obtained if the gas-oil contact has not been determined, to the oil-water contact or the lowest point at which an oil or gas flow is obtained based on reservoir and well testing results, and well log data, if the oil-water contact has not been determined.

- For gas: From the top of the reservoir to the gas-oil contact, or to the lowest point at which an oil or gas flow is obtained if the gas-oil contact has not been determined.

2.2. Probable (P2)

P2 shall be determined using the half-way method (Figure 1), specifically as follows:

2.2.1 For oil or gas reservoirs: From the oil down to (ODT) or gas down to (GDT) to the midpoint of the ODT or GDT and the water up to (WUT) or the structural spill point (SP).

2.2.2 For oil reservoirs with a gas cap:

- For gas: From the GDT to the midpoint of the GDT and the oil up to (OUT).

- For oil: From the OUT to the midpoint of the GDT and the OUT.
 

- From the ODT to the midpoint of the ODT and the WUT, or the SP if the WUT has not been determined.

For massive reservoirs with high heterogeneity, the P2 shall be determined from the ODT or GDT to the lowest point with oil and gas shows during drilling. If the lowest point with oil and gas shows has not been determined, the half-way method shall be applied to the spill point.

2.3. Possible (P3)

P3 shall be determined using the half-way method (Figure 1), specifically as follows:

From the midpoint of the ODT or GDT - WUT, or the midpoint of the ODT or GDT - SP if the WUT has not been determined, to the SP. Or most simply, from the lower boundary of the P2 level to the SP.

For massive reservoirs with high heterogeneity, the P3 shall be determined from the P2 boundary to the structural spill point.

3. Areal classification

Within a reservoir, the areas for P1 and P2 shall be determined based on the radius or half-way method (in case of multiple wells) estimated from the well, in conjunction with the vertical classification boundaries for petroleum resources and reserves.

The radius value shall be justified based on geological and geophysical data, well data, reservoir testing results, production data, or analogous methods. The P3 shall be applied to the remaining area of the reservoir, taking into account structural closure, spill point, or the maximum recorded oil or gas column height.

For massive reservoirs with high heterogeneity, the radius principle shall be applied along the well trajectory (Figure 2).

4. Other classification cases

4.1. Proved (P1)

4.1.1 Reservoirs that, after the application of stimulation techniques, achieve commercial oil or gas flow, even though the initial test did not result in natural flow or yielded weak flow that did not meet the criteria for Proved classification.

4.1.2 Reservoirs where wireline testing confirms the presence of oil and gas, and the collected data allows for the determination of the existence and distribution of oil and gas with the high confidence level, with analogous reservoirs in other wells having been confirmed through DST.

4.1.3 Reservoirs that have not been tested, but based on well log data, exhibit petrophysical characteristics and reservoir parameters similar to those of other wells that have achieved commercial flow or are producing from the same reservoir.

4.2. Probable (P2)

4.2.1 Reservoirs with potential for oil and gas flow based on well log data, petrophysical characteristics, and reservoir parameters, but with inconclusive well testing results.

4.2.2 Reservoirs where wireline testing confirms the presence of petroleum.

4.2.3 Reservoirs that show potential for petroleum flow based on well log characteristics but lack core data or definitive well testing results, and do not have characteristics similar to producing reservoirs or Proved reservoirs within the same area.

4.2.4 Reservoirs with similar porosity and permeability properties, in pressure communication, separated by a fault or a geological barrier, and structurally higher than a reservoir already classified as Proved.

4.2.5 Reservoirs adjacent to producing petroleum reservoirs, but well tests yield low flow rates.

4.2.6 Un-drilled blocks adjacent to a block with Proved petroleum reserves in a field is divided into blocks.

4.2.7 Reservoir intervals where infill drilling or other methods would increase reserves and meet the criteria for Proved classification, but at the time of resource and reserve assessment, infill drilling has not been conducted.

4.2.8 Reservoirs expected to be classified as Proved if further drilling is conducted, but at the time of resource and reserve assessment, drilling has not been conducted, and the structural map data is insufficient to classify them as Proved.

4.2.9 Due to the application of a developed and commercially available enhanced oil recovery (EOR) method, where the pilot project or testing program has been established and the equipment installed but not yet operational, and the reservoir rock and fluid properties and parameters support the commercial application of the enhanced oil recovery method.

4.2.10 Achieved through successful well workovers, treatments, re-treatments, equipment replacements, or other technical procedures, where these procedures have not been previously recognized as successful in similar wells and reservoirs.

4.2.11 Increased recovery potential from producing reservoirs or un-producing Proved reservoirs due to re-interpretation of reservoir dynamics or volumetric parameters.

4.3. Possible (P3)

4.3.1 Reservoirs with potential for petroleum accumulation located in a block adjacent to blocks with Proved or Probable reserves.

4.3.2 Reservoirs extrapolated within a structural complex with geological conditions similar to those of a Proved structure.  

4.3.3 Reservoirs extrapolated structurally or stratigraphically based on geological and geophysical interpretations beyond areas already classified as Possible.

4.3.4 Reservoirs that show evidence of petroleum based on well log data or core samples, but may not be commercially producible.

4.3.5 Due to the application of the enhanced oil recovery methods under a pilot project or a newly established program that is not yet operational, and where reservoir rock and fluid properties and parameters raise concerns about the commercial viability of the project.

4.3.6 Reservoirs with similar porosity and permeability properties, in pressure communication, separated by a fault or a geological barrier, and structurally lower than a reservoir already classified as Proved.

4.3.7 Increased recovery potential due to re-interpretation of reservoir dynamics or volumetric parameters, such as in-place volumes or recovery factor, indicating significant additional petroleum beyond those classified as Proved or Probable.

4.3.8 Large reservoir intervals with high risk:

- Areas with low seismic coverage.

- Reservoirs with unclear continuity and quality.

- Additional recovery from the enhanced oil recovery projects.

- Better average reservoir parameters

5. Classification of C1, C2, and C3

For sub-commercial discoveries and reservoirs, the C1, C2, and C3 shall be determined using criteria similar to those for P1, P2, and P3, respectively.

Figure 1. Principle of determining the boundary (for estimation) of resource and reserve levels for layered reservoirs.

Figure 2. Principle of determining the boundary (for estimation) of resource and reserve levels for massive reservoirs

II. JUSTIFYING PETROLEUM RESOURCES AND RESERVES PARAMETERS

When estimating petroleum resources (initially-in-place petroleum) and reserves using the conventional volumetric method, the following parameters need to be justified and determined: area, reservoir volume, effective pay thickness, porosity, petroleum saturation, volume conversion factor, oil density, gas-oil ratio (GOR), condensate-gas ratio (CGR), and recovery factor. These parameters must be justified for the confidence level based on the statistical probability distribution of values determined from geological and geophysical data, reservoir engineering data, production data, and analogous methods. The estimated petroleum resources, reserves, and potential recovery by the defined method must be expressed at minimum (P90 – 90% confidence level), expected (P50 – 50% confidence level), and maximum (P10 – 10% confidence level) levels.

1. The area and volume of the reservoir shall be determined separately for each reservoir and for each classification level based on the calculation maps generated from the structural maps of the top and base of the reservoir and the vertical classification boundaries.

2. The effective pay thickness and net-to-gross ratio (NTG) shall be determined separately for each reservoir and for each classification level based on well log data or weighted average according to the reservoir volume.

3. Porosity shall be determined separately for each reservoir and for each classification level based on well log data and core samples.

4. Petroleum saturation shall be determined separately for each reservoir and for each classification level based on a combination of laboratory core sample analysis and well log data.

5. The oil or gas conversion factor shall be determined in the laboratory from petroleum samples obtained from exploration and production wells.

6. The gas-oil ratio (GOR) or the gas content in reservoirs, and the condensate-gas ratio (CGR) or the condensate content in free gas, shall be determined from laboratory analysis of petroleum samples obtained during exploration and production.

7. The cutoff values for the parameters shall be determined separately for each reservoir or be taken analogously from reservoirs with core sample analysis within the same field or neighboring fields.

7.1. Permeability: The cutoff permeability of the reservoir rock for each productive layer shall be determined from laboratory analysis of core samples from that productive layer.

7.2. Porosity: The cutoff porosity of the reservoir rock for each layer shall be the porosity value corresponding to the cutoff permeability for that layer.

7.3. The cutoff residual water saturation for each layer shall be the residual water saturation determined from core sample analysis corresponding to the cutoff permeability for that layer.

For fields and reservoirs in the commercial category, it is mandatory to estimate the initially in-place petroleum reserves using 3D geological models, 3D production simulation models, production analysis, and material balance to compare the results, depending on the availability of data.

III. JUSTIFYING THE RECOVERY FACTOR

1. The recovery factor for petroleum shall be justified and determined using analogous methods separately for each reservoir and averaged for the entire field, based on the application and potential application of new enhanced oil recovery (EOR) techniques and technologies during the production to achieve the objective of maximum recovery.

2. The recovery factor shall be justified based on the reservoir's hydrodynamic model, considering different production plans, or by referencing analogous recovery factors from neighboring fields with similar geological characteristics and hydrodynamic properties if a hydrodynamic model has not been developed. The reservoir's hydrodynamic model shall be built based on actual data, including laboratory research results, well log surveys, and hydrodynamic surveys of exploration and appraisal wells, and production analysis (if available). The recovery factor for the reservoir shall be selected based on the optimal production plan, including well density, injection and production methods, secondary and tertiary recovery methods (e.g., pressure maintenance methods, drilling schedule and well start-up timing, and other methods to enhance recovery, etc.)

3. The recovery factor for Possible reserves and petroleum resources shall be determined by referencing analogous recovery factors from higher reserve categories within the same field.

4. For the initial report of petroleum discoveries, the recovery factor shall be determined based on: (i) a hydrodynamic model; (ii) or a preliminary hydrodynamic model; (iii) or referring to the recovery factors from neighboring fields with similar geological structure and hydrodynamic properties; (iv) or statistical analysis of recovery factors from reservoirs with similar geological characteristics within the same sedimentary basin or region; (v) or statistical analysis of recovery factors from reservoirs with similar geological characteristics in other areas of the world; (vi) or other methods accepted in international petroleum industry practice.

APPENDIX III

Template for petroleum resources and reserves report

(Issued together with Circular No. 13/2024/TT-BCT dated August 8, 2024 of the Minister of Industry and Trade)

PETROLEUM RESOURCES AND RESERVES REPORT FOR FIELD/DISCOVERY ...

BLOCK ..., BASIN ...

(as of ...(month)... ...(year)...)

PART I. EXPLANATORY

1. Introduction

2. History of petroleum exploration, appraisal, development, and production

3. Database

Statistics on methods, quantity, and quality assessment of data:

3.1. Seismic survey data and other geophysical exploration methods (electrical, magnetic, gravity, etc.): survey grid, field data, processed data.

3.2. Drilling data: Overview of wells (within the field and relevant surrounding areas), well log data, core samples, cuttings, well testing results, sample analysis, hydrodynamic studies, production or production testing (if any).

3.3. Production data (if any).

3.4. Data from other surveys and studies (biostratigraphy, sedimentary petrology, geochemistry, etc.).

4. Regional geology, field geology

4.1. Regional geology

4.2. Field geology

4.2.1 Interpretation of geophysical data:

- Determining seismic horizons, seismic-to-well tie, generating time-structure maps, time-to-depth conversion, depth structure maps, time and depth sections, and isopach maps of corresponding seismic horizons;

- Seismic attributes and results of special seismic studies;

- Results of other geophysical exploration methods (electrical, magnetic, gravity, etc.).

- Error and risk assessment;

- Outstanding issues and proposed solutions.

4.2.2 Field geological structure:

 - Stratigraphy, depositional environment, and geology of the petroleum reservoirs;

- Tectonics: fault system, folding, and the impact of tectonic activity on the formation of petroleum traps and the field's geological structure;

- Hydrocarbon shows;

- Petrophysical characteristics and petroleum reservoir characteristics;

- Determination and correlation of petroleum reservoirs.

5. Reservoir parameters

5.1. Geological formation of petroleum reservoirs (structural maps, isopach maps, net-to-gross (NTG) ratio, fluid contacts, etc.).

5.2. Well log:

- Methods for determining the mass and quality of sample data and measurements;

- Methods and results of interpretation of reservoir parameters: porosity, permeability, petroleum saturation, effective pay thickness, etc., from well log data, core samples, and their cutoff values;

- Outstanding issues and proposed solutions.

5.3. Reservoir engineering:

- Properties, boundaries, and dynamics of reservoir water;

- Properties of petroleum at reservoir conditions and standard conditions;

- Reservoir temperature and pressure.

5.4. Reservoir testing results (DST), wireline-based reservoir testing results (MDT, RFT, RCI, mini-DST, etc.).

5.5. Production results and dynamics.

5.6. Oil-gas-water injection (if any).

6. Petroleum initially-in-place, petroleum reserves

6.1. Methods and formula for estimating petroleum initially-in-place and petroleum reserves (geological model, production model, material balance, analogy, etc.).

6.2. Determining boundaries and classifying petroleum initially-in-place and petroleum reserves.

6.3. Selecting parameter values: reservoir volume, effective pay thickness, net-to-gross ratio, porosity, petroleum saturation, and other fluid parameters.

6.4. Estimating petroleum initially-in-place and petroleum reserves for each fluid type, according to reservoirs, massive reservoirs, area, and the entire field.

6.5. Justifying the recovery factor, the results of petroleum initially-in-place and petroleum reserve estimations, and condensate for each reservoir, massive reservoir, area, the entire field, and the remaining petroleum reserves.

6.6. The results of petroleum initially-in-place and petroleum reserve estimations using other methods (geological model, production model, material balance, analogy, etc.); comparing, justifying, and selecting the final estimation results for the entire field according to the petroleum contract phases and after the petroleum contract termination.

6.7. Comparing the estimated results of petroleum initially-in-place and petroleum reserve with the previously approved results of petroleum initially-in-place and petroleum reserve, explaining the reasons for changes.

6.8. Assessing the confidence level of the estimated values for each classification level.

6.9. Outstanding issues and proposed solutions.

7. Conclusions and recommendations

7.1. Assessing the level of geological and geophysical, and reservoir engineering studies; results of exploration and production; estimation results, and outstanding issues to be addressed.

7.2. Proposing further exploration, appraisal, and research activities.

7.3. Recommending the competent authorities to approve the petroleum initially-in-place of the field or discovery as the basis for implementing subsequent activities.

PART II. APPENDIX: TABLES, DRAWINGS, AND DATA

The Appendix includes all necessary documents and texts related to exploration, evaluation, resource estimation, and estimation of the petroleum reserves of the field. It also includes data tables, statistical charts, estimation results, maps, cross-sections, and diagrams, etc. which serve to illustrate and supplement the explanatory part of the report. Additionally, these materials meet the requirements for the verification and validation of the report by competent authorities.

I. TABLES

The tables in the Appendix must contain both raw and intermediate data, as well as other relevant information necessary for verifying the results of petroleum initially-in-place and petroleum reserve estimations. The following tables and information must be included:

1. Drilling volume for exploration, appraisal, and development; production drilling: Well name, coordinates, sea depth, well type, drilling rig, drilling time (start date, end date), designed or actual depth, stratigraphy, well results, and current status of the well, etc.

2. Drilling volume for production, injection, monitoring, and other production support wells, as well as information on well completion.

3. Volume of core samples, cuttings samples, fluid samples, and types of analysis.

4. Well testing results and studies within the well.

5. Combination of well logging data and other surveys performed.

6. Interpretation results of well log data.

7. Chemical composition and physical properties of reservoir water.

8. Petrographic, paleontological, stratigraphic, sedimentary environment data, etc., for the petroleum reservoirs, or productive layers.

9. Composition and physical-chemical properties of reservoir fluids: oil, dissolved gas, free gas, and condensate.

10. Results of porosity, permeability, and petroleum saturation analysis, as well as other reservoir parameters from core samples (if available).

11. Input parameters for estimating petroleum initially-in-place, dissolved gas, free gas, and condensate.

12. Comparison of accepted parameters when re-estimating petroleum initially-in-place and petroleum reserves with previously approved data.

13. Comparison with previously approved data.

14. Data on reservoir dynamics and results of production or production testing (if any).

II. DRAWINGS

1. Overview map of the area and the location of the field and discovery.

2. Map of seismic line network and exploration, appraisal well locations.

3. Composite stratigraphic column of the field.

4. Representative seismic cross-sections (both uninterpreted and interpreted) representing the entire field.

5. Time-structure and depth-structure maps of seismic horizons, and petroleum reservoirs

6. Isopach maps of structural layers in the stratigraphic units, and petroleum reservoirs.

7. Geological cross-sections through the wells.

8. Geological cross-sections of the petroleum reservoirs of the field through the wells.

9. Diagrams and tables presenting the results of correlating the petroleum reservoirs through the wells.

10. Structural maps of the top and base of petroleum reservoirs.

11. Isopach map of the petroleum reservoir.

12. Vertical and horizontal geological and seismic cross-sections of the field.

13. Geological cross-sections of the petroleum reservoirs.

14. Correlation of petroleum reservoir through the wells.

15. Classification diagram for petroleum reservoirs.

16. Well log curves and summaries, as well as results from interpretation of well log data and reservoir testing for each well with a vertical scale 1/500.

17. Core sample analysis results and core description.

18. Data and results of reservoir testing and flow testing, and production (if any): Production (oil, gas, water), pressure dynamics, temperature, monitoring, well testing, etc.

19. References list, including related documents and reports used in preparing the report.

20. Reports, data, analytical results, numerical calculation models on electronic computing systems, lists and information on software programs applied for estimations.

III. DATA

The data and results of interpretation, processing, and simulation of geological-geophysical documents, reservoir engineering technology on technical software used in the preparation of the report.