Circular No. 24/2020/TT-BCT stipulates on the分级和编制石油资源和储量报告的规定

ANNEX I

Discovered oil and gas resources in development group

P1

 

 

 

ANNEX II

A reservoir layer is defined by the top and bottom of the layer, fault barriers, structural closure, facies boundaries, stratigraphic pinchouts, or other separating boundaries.

P1

A reservoir block is defined by its top, fault barriers, structural closure, non-permeable boundaries, or other separating boundaries.

The determination of reservoirs is based on structure maps, conventional seismic data, special seismic data, hydrodynamic data, well test information, production data, and other relevant materials.

Classification of oil and gas resources and reserves must be conducted for each reservoir.

II. Vertical Classification

The boundaries of the classification levels of oil and gas resources and reserves are determined using the half-way method or other methods utilizing geological, geophysical, and mining technology data with clear theoretical foundations and analysis.

1. Verification Level - P1

The verification level P1 is determined as follows (Figure 1):

a) 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 deepest point where oil or gas flow was observed during well testing and logging, if the OWC or GWC is not determined.

b) For oil reservoirs with a gas cap:

- For oil: From the oil-gas contact or the highest point where oil was encountered if the oil-gas contact is not determined, to the OWC or the lowest point where oil flow was observed during well testing and logging, if the OWC is not determined.

- For gas: From the top of the reservoir to the gas-oil contact or to the lowest point where gas flow was observed if the gas-oil contact is not determined.

2. Probable Level - P2

The probable level P2 is determined according to the half-way method as follows:

a) For oil or gas reservoirs: From the oil-down-to (ODT) or gas-down-to (GDT) point to the midpoint of the ODT or GDT-water-up-to (WUT) interval or the spill-point (SP).

b) For oil reservoirs with a gas cap:

- For gas: From the GDT point to the midpoint of the GDT-out-to (OUT) interval.

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

- From the OpT point to the midpoint of the ODT-WUT interval or the spill-point (SP) if the WUT point is not determined.

For highly heterogeneous reservoir blocks, the P2 level is determined from the ODT or GDT point to the deepest point showing oil or gas indications during drilling. If the deepest point showing oil or gas indications cannot be determined, the half-way method is applied up to the spill-point.

3. Possible Level - P3

The possible level P3 is determined according to the half-way method as follows (Figure 1):

From the midpoint of the ODT or GDT-WUT interval or the midpoint of the ODT or GDT-spill-point (SP) interval if the WUT point is not determined to the SP; or simply from the lower boundary of the P2 level to the SP.

For highly heterogeneous reservoir blocks, the P3 level is determined from the P2 level boundary to the spill-point.

III. Area Classification

Within a reservoir, the area of the P1 and P2 levels is determined according to the radius principle or the half-way method (in cases with multiple wells) measured from the drilling well combined with the vertical classification line of oil and gas resources and reserves.

From the midpoint of the interval ODT or GDT - WUT or from the midpoint of the interval ODT or GDT - the spill point (SP) if the WUT has not been determined to the spill point (SP); or simply from the lower boundary of P2 to the spill point (SP).

For oil and gas reservoirs with high heterogeneity, the P3 level is determined from the boundary of P2 to the spill point (SP).

III. Classification by area

In a reservoir, the areas of P1 and P2 levels are determined according to the principle of radius or dividing the distance (in cases with multiple wells) measured from the drilling well in conjunction with the resource and reserve boundaries of oil and gas vertically.

The radius value is argued based on geological and geophysical data, wells, formation tests, production, or similar methods. The P3 category is applied to the remaining part of the reservoir body up to the structural closure, spill point, or the highest statistically recorded oil column height.

For reservoir bodies in block form, the radius principle applies along the well trajectory (Figure 2).

IV. Some other cases for resource classification

1. Verification Level P1

a) Reservoirs that, after applying formation stimulation measures, achieve commercial flow rates of oil and gas, even though previous tests did not result in natural flow or weak flows insufficient for verification level classification;

b) Reservoirs where cable testing confirms the presence of oil and gas, with collected materials allowing for a high degree of confidence in the existence and distribution of oil and gas, and co-name reservoirs at other wells have been verified through DST results;

c) Reservoirs that have not yet been tested but, according to well geophysical data, have lithological characteristics and reservoir parameters similar to those of other wells that have achieved commercial flow rates or are currently being produced from the same reservoir.

2. Potential Level P2

a) Reservoirs that have the potential for oil and gas flow based on well geophysical data, lithological features, and reservoir parameters, but with unclear formation test results;

b) Reservoirs where cable testing confirms the presence of oil and gas;

c) Reservoirs that show potential for oil and gas flow based on well geophysical characteristics but lack core samples or clear formation test results and do not have similar characteristics to producing or verified reservoirs within the same area;

d) Reservoirs with similar permeability properties, adjacent under pressure, separated by faults or geological barriers, and located structurally higher than verified reservoirs;

đ) Reservoirs adjacent to producing oil and gas reservoirs, but formation tests only yield small flow rates of oil;

e) Blocks that have not been drilled but are adjacent to blocks with verified oil and gas reserves in divided fields;

g) Portions of reservoirs if densely drilled or otherwise increased would meet the conditions for verification level classification, but at the time of resource calculation, such drilling has not been carried out;

h) Reservoirs expected to be classified as verification level if expanded drilling is conducted, but at the time of resource calculation, they have not been drilled and the structure map data is insufficient to classify them at that level;

i) Due to the completion and commercialization of enhanced recovery methods when the project or experimental program has been established and installed but not yet operated, and the rock properties, fluid characteristics, and reservoir parameters ensure favorable conditions for the commercial application of these methods;

k) Obtained through successful repair, treatment, reprocessing, replacement of well equipment, or other technical processes, but these processes were previously not recognized as successfully applied in wells with similar conditions and in similar reservoirs;

l) Increased from producing or verified reservoirs but not yet developed due to reanalysis or reinterpretation of reservoir dynamics or volumetric parameters;

3. Potential Level P3

a) Reservoirs with the potential to accumulate oil and gas located in blocks adjacent to verified or potential blocks;

b) Reservoirs extrapolated within a cluster of structures with geological conditions similar to those already verified;

c) Reservoirs extrapolated based on structure and/or stratigraphic analysis and interpretation of geological and geophysical data outside areas classified as potential;

d) Reservoirs showing oil and gas content based on well geophysical data or core samples but potentially not yielding commercial flow rates;

đ) Due to the application of enhanced recovery methods according to new experimental programs or projects that have only been established but not yet operated, and rock properties, reservoir fluid characteristics, and parameters still raise objective doubts about the commerciality of the project;

e) Reservoirs with similar permeability properties, adjacent under pressure, separated by faults or geological barriers, and located structurally lower than verified reservoirs;

g) Increased due to reanalysis or reinterpretation of reservoir dynamics or volumetric parameters, such as oil and gas volume parameters at the reservoir and/or recovery factors, indicating significant additional quantities of oil and gas beyond those classified at verification and potential levels;

h) Large-volume oil and gas reservoir portions but with high risk:

- Areas with low seismic coverage data.

- Reservoirs with unclear continuity and quality.

- Additional recovery through the application of enhanced recovery processes.

- Better average reservoir parameters.

V. Classification Levels C1, C2, and C3

For discoveries and undeveloped reservoirs, levels C1, C2, and C3 are determined based on criteria similar to levels P1, P2, and P3 respectively.

Figure 1. Schematic diagram of resource and reserve classification for reservoirs in layer form

Figure 2. Schematic diagram of resource and reserve classification for reservoirs in block form

B. ARGUMENTATION OF OIL AND GAS RESERVE PARAMETERS

When calculating initial in-place oil and gas volumes using conventional volume methods, the parameters to be argued and selected include: reservoir area, reservoir volume; effective thickness for oil and gas storage; porosity and oil saturation; volume conversion factor; oil density; gas-oil ratio (GOR), condensate-gas ratio (CGR). These parameters must be argued based on the level of reliability derived from the statistical probability distribution of values determined from geological and geophysical data and mining technology. Calculation results must be presented at minimum (P90), expected (P50), and maximum (P10) levels corresponding to the probabilities of input parameters.

1. Reservoir area and volume are determined separately for each reservoir and by category based on calculation maps prepared based on top and bottom structure maps.

2. The effective thickness and the effective porosity coefficient (NTG) are determined separately for each reservoir layer and at each level based on well logging physical geological data or weighted average according to the volume of each reservoir layer.

3. Porosity is determined separately for each reservoir layer and at each level based on well logging physical geological data and core samples.

4. Hydrocarbon saturation is determined separately for each reservoir layer and at each level. Hydrocarbon saturation is determined based on the combination of laboratory core sample analysis results and well logging physical geological data.

5. The conversion factor for oil or gas is determined in the laboratory using oil and gas seam samples obtained from wells.

6. The gas-oil ratio (GOR) or gas content in oil seam, condensate-gas ratio (CGR) or condensate content in free gas is determined based on the research results of oil and free gas in the laboratory.

7. The threshold values of calculated parameters are determined separately for each reservoir layer or taken similarly from seams that have been analyzed with core samples in the same field or adjacent fields.

- Permeability: The threshold permeability value of each producing layer/reservoir is determined based on laboratory analysis results using core samples from that specific producing layer.

- Porosity: The threshold porosity value of each producing seam is the corresponding porosity value at the threshold permeability for that specific producing seam.

- The threshold water saturation of each producing seam is the water saturation value determined based on the analysis of core samples from the corresponding producing seam at its threshold permeability.

For fields and reservoirs belonging to the development category, the initial in-place hydrocarbons, hydrocarbon reserves must be calculated using 3D geological modeling methods, 3D production simulation, and material balance, depending on the available data.

C. ARGUMENTATION OF OIL AND GAS RECOVERY FACTOR

The recovery factor (RF) for oil and gas is argued separately for each reservoir layer and averaged for the entire field based on the application and potential application of new achievements in oil and gas extraction technology to achieve the maximum possible oil and gas recovery from underground.

RF is argued based on the hydrodynamic model of the reservoir layer according to different production design options or referencing the RF of reservoir layers from nearby fields with similar structural, geological characteristics, and hydrodynamic features when a hydrodynamic model has not been established. The hydrodynamic model of the reservoir layer is built based on practical data such as laboratory research results, well logging physical geological surveys, and hydrodynamic surveys of exploration, appraisal, and production wells (if applicable). The RF of the reservoir layer is selected based on the optimal production plan such as the density of production wells, injection, secondary and tertiary recovery methods (for example: pressure maintenance methods, drilling progress, drilling rate, and bringing wells into production...).

RF for potentially recoverable reserves and resources is referenced based on similar RF as higher-grade reserves of the same field.

For initial discovery reports of oil and gas, the RF for oil and gas is determined based on: (i) hydrodynamic models; (ii) or preliminary hydrodynamic models; (iii) or referencing the RF of reservoir layers from nearby fields with similar geological structures and hydrodynamic features; (iv) or statistics of RF from reservoir layers with similar geological characteristics in the same sedimentary basin, in the same area; (v) or statistics of RF from reservoir layers with similar geological characteristics from other regions around the world; (vi) or other methods accepted in international oil industry practices.

 

ANNEX III

P1

REPORT ON RESOURCES AND RESERVES OF THE OIL/GAS FIELD/DISCOVERY...

BLOCK......, BASIN......

(documents up to month____ year______)

PART I. INTRODUCTION OF THE REPORT

1. Introduction

2. History of Exploration, Surveying, Evaluation, Development, and Exploitation of the Mine

3. Database

Statistical Methods, Volume, and Quality Assessment of Materials:

3.1. Seismic Survey Materials and Other Geophysical Exploration Methods (Electrical, Magnetic, Gravity...Survey Networks, Field Data, Processing Data)

3.2. Drilling Materials: Overview of Wells (Within the Mine and Adjacent Areas), Well Logging Geophysical Data, Core Samples, Cuttings, Reservoir Testing Results, Analysis of Various Types of Samples, Hydrodynamic Research, Production/Trial Production (if applicable)

3.3. Other Survey and Research Materials (Paleontology, Sedimentary Petrology, Geochemistry...)

4. Geology

4.1 Regional Geology

4.2 Mine Geology

4.2.1 Interpretation of Geophysical Materials:

- Determining Seismic Layer Characteristics, Correlation with Drilling Wells, Construction of Time-Equivalent Maps, Time-Depth Conversion, Depth-Equivalent Maps, Time-Slice Maps, and Thickness-Equivalent Maps of Corresponding Seismic Layers.

- Seismic Attributes and Special Seismic Research Results.

- Results of Other Geophysical Exploration Methods (Electrical, Magnetic, Gravity...).

- Existing Issues and Proposed Solutions.

4.2.2 Geological Structure of the Mine

- Sedimentary Strata

- Tectonics: Fault Systems, Folding, and Impact of Tectonic Activities on the Formation of Oil and Gas Structural Traps.

- Oil and Gas Indicators.

- Identification and Correlation of Oil and Gas Reservoirs.

- Petrological and Depositional Environment Characteristics of Oil and Gas Reservoirs.

5. Reservoir Parameters

5.1 Geological Structure of Oil and Gas Reservoirs (Structural Maps, Thickness-Equivalent Maps, Effective Rock Volume Coefficient NTG, Fluid Flow Boundaries...).

5.2 Well Logging Geophysics:

- Methodology for Quantifying and Qualifying Survey Data

- Methodology and Interpretation Results of Reservoir Parameters: Porosity, Permeability, Oil and Gas Saturation, Effective Thickness... Based on Well Logging Geophysical Data, Core Samples, and Their Threshold Values.

- Existing Issues and Proposed Solutions.

5.3 Mine Technology:

- Properties and Behavior of Reservoir Water;

- Properties of Oil and Gas Under Reservoir Conditions and Standard Conditions;

- Reservoir Temperature and Pressure...

5.4 Reservoir Testing Results (DST), Wireline Testing (MDT, RFT, RCI, Mini-DST,...).

5.5 Production and Injection Testing Results of Oil, Gas, and Water (if applicable).

6. Initial In-Place Oil and Gas Reserves, Proven Reserves

6.1 Methods and Formulas for Calculating Initial In-Place Oil and Gas Reserves, Proven Reserves.

6.2 Determination of Boundaries and Classification of Initial In-Place Oil and Gas Reserves, Proven Reserves.

6.3 Selection of Values for Parameters: Rock Volume, Effective Thickness, Effective Rock Volume Coefficient, Porosity, Oil and Gas Saturation, and Other Fluid Parameters.

6.4 Calculation Results of Initial In-Place Oil and Gas Reserves, Proven Reserves by Type of Fluid, by Reservoir, Block, Area, and for the Entire Mine.

6.5 Discussion on Recovery Factors, Calculation Results of Initial In-Place Oil and Gas Reserves, Proven Oil, Gas, and Condensate Reserves for Each Reservoir, by Block, Area, Entire Mine, and Remaining Reserves.

6.6 Calculation Results of Initial In-Place Oil and Gas Reserves, Proven Reserves Using Other Methods (Geological Models, Production Models, Material Balance...); Comparison and Discussion with Results from Volume-Based Methods.

6.7 Comparison of Calculated Initial In-Place Oil and Gas Reserves, Proven Reserves with Previously Approved Initial In-Place Oil and Gas Reserves, Reasons for Changes.

6.8 Evaluation of Reliability of Calculated Figures at Different Levels.

6.9 Existing Issues and Proposed Solutions.

7. Conclusions and Recommendations

7.1 Evaluation of Geological and Geophysical Research, Mine Technology; Exploration and Exploitation Results, Calculation Results, and Issues to be Addressed.

7.2 Recommendations for Future Exploration, Evaluation, and Research Work.

7.3 Recommendation to the Prime Minister for Approval of Initial In-Place Oil and Gas Reserves and Recognition of Proven Reserves of the Mine, Discovery, as a Basis for Further Work.

PART II. APPENDICES OF TABLES, CHARTS, DRAWINGS AND DATA

The appendices include necessary documents and texts related to exploration, assessment, and reporting on oil and gas reserves of the field, including statistical tables, calculation results, maps, cross-sections, diagrams, etc., to illustrate and supplement the explanatory section of the report and to meet the requirements for reviewing and evaluating the report by competent authorities and organizations.

A. TABLES AND CHARTS

Tables and charts in the appendices must contain original and intermediate data necessary for checking initial oil and gas calculations, reserves, and must include the following tables:

1. Drilling volume for exploration, appraisal, and development: Well name, coordinates, sea depth, well type, drilling rig, drilling time (start and end date), designed or actual depth, bottom formation, well result and current status...

2. Development drilling volume.

3. Core sample, cuttings, fluid, and analysis volumes.

4. Results of reservoir testing and well study.

5. Well logging suites performed.

6. Interpretation results of well logging data.

7. Chemical composition and physical properties of formation water.

8. Petrographic, paleontological, stratigraphic, and sedimentary environment data of hydrocarbon reservoirs or producing zones.

9. Composition and physicochemical properties of fluids: Oil, dissolved gas, free gas, condensate.

10. Average values of permeability, porosity, and hydrocarbon saturation from core samples (if available).

11. Input parameters for initial oil and gas in-place calculation, oil and gas reserves.

12. Comparison of accepted parameters for recalculating initial oil and gas in-place and reserves with previously approved data.

13. Comparison with previously approved data.

14. Production or test production data (if available).

B. DRAWINGS

1. General map of the area and location of the field, discovery.

2. Seismic line network and exploration and appraisal well map.

3. Integrated stratigraphic column of the field.

4. Representative seismic sections (uninterpreted and interpreted).

5. Isochron and isodepth maps of seismic layers.

6. Isopach maps of structural layers of hydrocarbon-bearing units.

7. Geological cross-sections through wells.

8. Geological cross-sections of producing reservoirs through wells.

9. Diagrams and tables of reservoir connection results through wells.

10. Roof and base structure maps of hydrocarbon-bearing intervals or pools.

11. Isopach maps of hydrocarbon-bearing intervals or pools.

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

13. Geological cross-sections of hydrocarbon-bearing intervals.

14. Hydrocarbon-bearing interval connections through wells.

15. Classification diagrams for hydrocarbon-bearing intervals.

16. Interpretation results of well logging data and reservoir testing of hydrocarbon-bearing intervals or pools of each well - scale 1/500.

17. Well log curves and composite curves - scale 1/500.

18. Analysis and description results of core and cuttings samples.

19. Testing and production flow test data (if available): production volume (oil, gas, water), pressure, temperature, well monitoring and inspection...

20. List of documents used to prepare the report, other relevant documents and reports.

21. Computer-generated prints and software programs applied for calculations.

C. DATA

Data and interpretation, processing, and simulation results of geological and geophysical materials, and mining technology on technical software used in preparing the report.