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Hydrocarbon reserve estimation project report for Alywn Northfield (East Brent)

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By Glory Ibeh, Shola Arogs and Wale Ajayi

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Hydrocarbon reserve estimation project report for Alywn Northfield (East Brent)

  1. 1. Hydrocarbon-In-Place Estimation Project Report for Alwyn North Field [East Brent Panel] APRIL 2018 GROUP 6 AJAYI OLAWALE ISAAC G2017/IPS/MSC/PPD/297 AROGUNDADE OLUSHOLA G2017/IPS/MSC/PPD/300 IBEH NAOMI GLORY G2017/IPS/MSC/PPD/304
  2. 2. Page | II CERTIFICATION We hereby declare that the contained report on “OOGIP Calculation & Uncertainties” was researched, and the results thoroughly analyzed under the supervision of the project supervisor Mr. Owil Naleimolabh and approved, having satisfied the requirements to meet project objectives for Petroleum Engineering and Project Development (MSc.), UNIPORT/IFP School, Port-Harcourt, Rivers state, Nigeria.
  3. 3. Page | III ACKNOWLEDGEMENT First of all, we would like to acknowledge the Lord above all for his guidance, protection, wisdom and understanding throughout this project, also for the knowledge gained in the process, it has been a blessing. We also appreciate University of PortHarcourt and the IFP School for the opportunity to work as a team which contributed to developing team-building spirit amongst ourselves. We would also like to thank our project supervisor, Mr. Owil Naleimolabh for his guidance and direction in the course of this project, and for his advice and sacrifice we want to use this medium to appreciate the efforts we put in as a team, the drive, selflessness, and solidarity amongst us. We also appreciate all teams in IPS Batch 15 for their help and brainstorming arguments, it helped us all grow. God bless you all.
  4. 4. Page | IV NOMENCLATURE 3D 3-Dimension Bo Oil Formation Volume Factor DAT Depth-Area-Thickness FWL Free Water Level GOC Gas Oil Contact HCIIP Hydrocarbon Initially in Place N Ness OIIP Oil Initially In Place N Neutron Porosity Reading D Density Porosity Reading PVT Pressure-Volume-Temperature RFT Repeat Formation Test T Tarbert UKCS United Kingdom Continental Shelf WOC Water – Oil Contact WUT Water Up to
  5. 5. Page | V EXECUTIVE SUMMARY Reserves estimation is one of the most essential tasks in the petroleum industry. It is the process by which the economically recoverable hydrocarbons in a field, area, or region are evaluated quantitatively. The aim of this project was to estimate the Hydrocarbon-In-Place for Alwyn North field (Brent East Reservoir) using the given field data. Four wells (wells A2, N3, N1 and A4) were drilled to help estimate hydrocarbon. The volumetric method was used for the purpose of the estimation taking into account reserves uncertainty. Three cases of uncertainty were considered: minimum, average and maximum case. The sandstones in the formation are acting as a source rock for the emergence of the petroleum. The results showed the following conclusions:  Well to well correlations showed geological structures showed the presence of two faults and some folds.  All the wells had about the same WOC showing that the reservoir is continuous and connected and there is a high likelihood that the faults are non-sealing.  Ness 1 was in the aquifer zone and could not be produced from.  Tarbert 3 has the highest reservoir thickness with the best reservoir petrophysical characteristics (permeability, oil saturation and porosity) making it the most contributor to the estimated reserve. Tarbert 2 has a lot of mica embedded in its sandstones.  T3 has the highest GRV contributed mainly by its massive sandstone beds.  The Tarbert 3 holds the major portion of the trapped hydrocarbons in Brent East. The reserves were estimated as: - Minimum case = 19,253,824.44 m3 - Average case = 31,421,555.11 m3 - Maximum case = 39,837,677.39 m3
  6. 6. Page | VI TABLE OF CONTENTS CERTIFICATION ..............................................................................................................................................II ACKNOWLEDGEMENT................................................................................................................................. III NOMENCLATURE ...........................................................................................................................................IV EXECUTIVE SUMMARY.................................................................................................................................. V TABLE OF CONTENTS ...................................................................................................................................VI LIST OF FIGURES............................................................................................................................................IX LIST OF TABLES............................................................................................................................................... X 1 INTRODUCTION.......................................................................................................................................1 1.1 Background ..............................................................................................................................................1 1.2 Objective and Scope..................................................................................................................................2 1.2.1 Objective.........................................................................................................................................2 1.2.2 Scope ..............................................................................................................................................2 2 DESCRIPTION OF FIELD........................................................................................................................3 2.1 Overview ..................................................................................................................................................3 2.2 Field Characteristics Tectonics...................................................................................................................4 2.2.1 Geological Setting............................................................................................................................4 2.2.2 Geological Description.....................................................................................................................5 2.2.3 Tectonics.........................................................................................................................................7 2.2.4 Sedimentology.................................................................................................................................8 2.3 Summary..................................................................................................................................................9 3 HYDROCARBON RESERVE ESTIMATION ........................................................................................ 10 3.1 Types of Reserves.................................................................................................................................... 10 3.2 Basic Definition....................................................................................................................................... 11 3.3 Methods of Estimating Reserves ............................................................................................................. 12 3.3.1 Volumetric Estimation ................................................................................................................... 13 4 METHODOLOGY.................................................................................................................................... 15 4.1 Overview of HCIIP Estimation.................................................................................................................. 15 4.2 Well logs Interpretation .......................................................................................................................... 15 4.2.1 Well to Well Surface Correlations................................................................................................... 16 4.2.2 Identification of Reservoir Zones and Thickness ............................................................................. 17
  7. 7. Page | VII 4.2.3 Identification of Fluid Contacts ...................................................................................................... 18 4.2.4 Quick-look Porosity Calculation in Water, Oil and Gas Zones .......................................................... 18 4.2.5 Determination of Resistivity of Formation Water ........................................................................... 18 4.3 Validation of Fluid Contacts Using RFT .................................................................................................... 19 4.4 Calculation of Petrophysical Properties.................................................................................................... 20 4.4.1 Net-to-Gross ratio, GN / ............................................................................................................ 20 4.4.2 Average Porosity ........................................................................................................................... 20 4.4.3 Average Initial Water Saturation.................................................................................................... 20 4.4.4 Determination of Absolute Permeability ........................................................................................ 21 4.5 Gross Rock Volume (GRV) Estimation ...................................................................................................... 21 4.5.1 DAT Procedure (Non-Eroded Zone)................................................................................................ 22 4.5.2 DAT Procedure (Eroded Zone)........................................................................................................ 22 4.6 PVT Selection- Formation Volume factor, Bo ......................................................................................... 23 4.7 Estimation of HCIIP ................................................................................................................................. 23 4.7.1 Assessment of Reservoir Uncertainties .......................................................................................... 24 4.7.2 Estimating of HCIIP Uncertainties................................................................................................... 24 5 RESULTS AND DISCUSSIONS............................................................................................................... 25 5.1 Introduction............................................................................................................................................ 25 5.2 Well Logs Interpretation ......................................................................................................................... 26 5.2.1 Well to Well Surface Correlations................................................................................................... 26 5.2.2 Logs Interpretation- Identification of Reservoir Zones.................................................................... 27 5.2.3 Resistivity and Saturation of Formation Water in the Aquifer (Formation N1)................................. 29 5.3 Validation of Fluid Contacts .................................................................................................................... 29 5.4 Petrophysical Properties and Net to Gross Ratio...................................................................................... 30 5.5 GRV Estimation....................................................................................................................................... 31 5.6 PVT Selection- Formation Volume factor, Bo ......................................................................................... 34 5.7 Estimation of HCIIP Including Uncertainties............................................................................................. 34 6 CONCLUSION.......................................................................................................................................... 36 REFERENCES................................................................................................................................................... 38
  8. 8. Page | VIII APPENDIX......................................................................................................................................................... 39 Appendix I: Resistivity and Saturation of Formation Water in the Aquifer (N1) ........................................ 39 Appendix II: Calculation of FVF ............................................................................................................ 39 Appendix III: Data Sheets Obtained During Calculation.............................................................................. 39
  9. 9. Page | IX LIST OF FIGURES Figure 1: 3D Area View of Alwyn North Field 3 Figure 2: Area Location Map of Alwyn North Field 4 Figure 3: Stratigraphy of Alwyn North Field 5 Figure 4: The Brent Geological Cross-section of Alwyn North Field 6 Figure 5: The Brent Geological Well Section of Alwyn North Field 6 Figure 6: The Cross-section through Alwyn Showing the Faults 8 Figure 7: Depositional Setting of the Brent group 9 Figure 8: Resource flow chart 11 Figure 9: Hydrocarbon Initially in Place Estimation Process 15 Figure 10: North-South direction and the West-East Directions of Correlations 16 Figure 11: Sample Phi-K for Unit N1 21 Figure 12: Eroded Surfaces 23 Figure 13: Well to Well Correlation a) North-South and b) West-East Cross- Sections 26 Figure 14: Sections of Interpreted Well Logs for Well a) A4 b) A2 c) N1 and d) N3 28 Figure 15: Pressure gradient curve for wells A4 and N3 29 Figure 16: Minimum case depth-area plot a) non-eroded zone and b) eroded zone 31 Figure 17: Average case depth-area plot a) non-eroded zone and b) eroded zone 32 Figure 18: Maximum case depth-area plot a) non-eroded zone and b) eroded zone 33
  10. 10. Page | X LIST OF TABLES Table 1: Data Received for Alwyn North (East Brent Reservoir).................................................1 Table 2: Reserve Estimation Methods .......................................................................................12 Table 3: Properties Obtained from Reservoir Rocks ..................................................................16 Table 4: Depth-Area data for Tarbert 3......................................................................................22 Table 5: Uncertain Reservoir Estimation Cases .........................................................................24 Table 6a: Petrophysical Properties (Porosity, Saturation, N/G, Stratigraphic Tops)....................30 Table 6b: Petrophysical Properties (Absolute Permeability) ......................................................31 Table 7: Summary of Minimum GRV .......................................................................................32 Table 8: Summary of Average GRV..........................................................................................33 Table 9: Maximum GRV...........................................................................................................33 Table 10: Differences in the PVT Study for Wells A4 and N3 ...................................................34 Table 11: Summary of Results (Minimum Case) .......................................................................34 Table 12: Summary of Results (Average Case) .........................................................................35 Table 13: Summary of Results (Maximum Case) ......................................................................35 Table 14: Well to Well Correlation Data Sheet a) North- South b) West- East...........................40 Table 15: Depth-Area Data Sheet a) Non-eroded b) Eroded ......................................................40 Table 16: Petrophysical Properties Data Sheet...........................................................................41
  11. 11. Page | 1 1 INTRODUCTION 1.1 Background Located 340 km NE from Aberdeen and 4 and 10km south of the Stratfjord and Brent field, the Alwyn North field was discovered in 1975 and operated by TOTAL since 1982. 2D and 3D seismic data obtained from the field indicated the presence of a petroleum system including source rocks, normal sealing faults with a general North-South direction, oil-bearing sandstones and a major unconformity at the base of the cretaceous. The unconformity is related to the of the Brent formation in the eastern Brent. The field is divided into six panels including the Brent East and North and also comprises eight blocks (3/4a‐ 6, 3/9a‐ 1, 2 and 3, 3/9a‐ 4 and 3/9a‐ 5 and 3/4a‐ 8). The first well (3/4a‐ 6) drilled in 1975 with oil in the Brent group and condensate gas in the Strafjord sandstone. Five appraisal wells; A1, A2, A3, A4 and A5 in block 3/9 were drilled between 1971 and 1982 to further confirm the presence of oil and condensate gas. It has been decided that the Hydrocarbon Initially in Place (HCIIP) will be estimated for the East Brent area. The volumetric method will be used in the estimation. This is to illustrate the concept of volumetric reserves estimate in this course taking into consideration uncertainties. To better understand the formation and obtain data that would be further used in reservoir and PVT studies, core and plug samples were collected from the drilled wells and have been analyzed in the laboratory. The wells were also logged to obtain well log data. Detailed results obtained from the analysis were received and will be used to estimate the reserve. Table 1 contains the data received. Table 1: Data Received for Alwyn North (East Brent Reservoir) S/N Title Description 1 Annex 1 Phi-k cross plots for Ness and Tarberts 2 Annex 4 Pressure measurement synthesis 3 Annex 5 PVT study for wells N3 and A4 4 Annex 6 N1, N3 vertical and deviated depths 5 Annex 7 Documentation for log interpretation
  12. 12. Page | 2 1.2 Objective and Scope 1.2.1 Objective The objective of this Engineering project is to estimate the hydrocarbons in place (HCIIP) for the Alwyn North Field (Brent East Reservoir) by undertaking the following specific activities: ● Interprete its well logs ● Calculate the petrophysical properties ● Estimate gross rock volume (GRV) ● Selecting the formation volume factor (FVF) ● Estimating the HCIIP while considering reservoir uncertainties 1.2.2 Scope The study was limited to the East panel of the Alwyn North field.
  13. 13. Page | 3 2 DESCRIPTION OF FIELD 2.1 Overview The Alwyn North Field was discovered in 1974 in the South Eastern part of the East Shetland Basin in the UK North-sea, about 140 km East of the near most Shetland Island and about 400 km North East of Aberdeen. The Alwyn field lie respectively 4 and 10 km south of Strathspey and Brent field, 7 km east of Ninian field, and 10 km north of Dunbar field (see field localization map below). The water depth is around 130 m. The field is in the UKCS Block 3/9 and extends northward into the Block 3/4. The location map and 3D view of the area is shown in figure 1 and 2 respectively. Figure 1: 3D Area View of Alwyn North Field
  14. 14. Page | 4 Figure 2: Area Location Map of Alwyn North Field 2.2 Field Characteristics Tectonics Tectonics played a significant role on the structure of ALWYN North field. Tensional movements leading to the development of the Viking Graben from the lower Permian times to Upper Jurassic generated a complex fault pattern. Several seismic data acquisition programs were carried out: 2D seismic in 1974 and 1977, and 3D in 1980/81. Seismic data analysis indicates that the oil bearing sands are controlled on one hand by normal sealing faults with a general North-South direction, on the other hand by a major unconformity at the base of Cretaceous. This unconformity is related to erosion of the Brent formation in the eastern part of ALWYN North field. In a bid to explore the Alwyn North field a thorough geological description of the field is necessary to ensure complete understanding of the geology of the area. The geological setting, sedimentology and other related aspects of the field are described in this section 2.2.1 Geological Setting The Brent formation was deposited in a deltaic and shallow marine environment during the Middle Jurassic period. The Statfjord formation was deposited in a fluvial and shallow marine environment during the Lower Jurassic period. Each panel has several pre-cretaceous tilted blocks (see Figure 3 below). The cap-rock is made of three on lapping shaly formations:
  15. 15. Page | 5  Heather formation: marine transgressive shales with thin limestone stringers, which is deposited after the tectonic activity.  Kimmeridge clay thick in the West, thin in the East, which is the main hydrocarbon source rock  Thick cretaceous sequence Figure 3: Stratigraphy of Alwyn North Field ALWYN North reservoirs were relatively unaffected by diagenesis due probably to an early hydrocarbon impregnation RFT shows that each panel had its own pressure regime. Water- oil contacts were identified at different depth. All the panels were independent from the other. 2.2.2 Geological Description The structure of Alwyn Brent East Block was generally an eroded monoclonal, with Base Cretaceous Unconformity (BCU) setting east and south limit, Spinal Fault setting west limit (separating Brent east from north and central west blocks), and a fault with sometimes very small throw setting north limit. East structure under BCU is quite complicated, and described under the generic term of slumps (linked to gravitational collapse of head blocks during Cretaceous erosion – similar as ones encountered in Brent field). In the Brent East panel, the oil zone is in a stratigraphic trap as shown below created by the erosion unconformity to the east, by a north -
  16. 16. Page | 6 south fault to the west (between A-1 and A-2 wells) and by a tranverse fault to the north. The Brent Geological Cross section is shown below. Figure 4: The Brent Geological Cross-section of Alwyn North Field The Brent geological well section is shown in Figure 5. Figure 5: The Brent Geological Well Section of Alwyn North Field
  17. 17. Page | 7 2.2.3 Tectonics Several seismic data acquisition programs were carried out: 2D seismic in 1974 and 1977, and 3D in 1980/81. Seismic data analysis indicates that the oil bearing sands are controlled on one hand by normal sealing faults with a general North-South direction, on the other hand by a major unconformity at the base of Cretaceous. This unconformity is related to erosion of the Brent formation in the eastern part of ALWYN North field following the seismic interpretation, ALWYN North field was divided into the following panels:  Brent North  Brent Northwest.  Brent Southwest.  Brent East.  Statfjord  Triassic The first four panels are oil bearing within the Brent. The Statfjord formation is a condensate gas reservoir with the Brent completely eroded. The underlying Triassic is gas bearing.
  18. 18. Page | 8 Figure 6: The Cross-section through Alwyn Showing the Faults 2.2.4 Sedimentology The Brent group is divided into three main units:  The Lower Brent (Broom, Rannoch and Etive formations),  The Middle Brent (Ness formations), and  The Upper Brent (Tarbert formations). The last two are the only oil-bearing formations in the Brent East panel. The Lower Brent formation was deposited in a shore-face (Rannoch) to coastal barrier (Etive) environment. The clastic reservoir is made of transgressive sandstone (Broom) and prograding sandstones (Rannochand Etive). Thus, the petrophysical properties range from low to medium permeability. This unit does not contain any oil in the Brent East reservoir. The Middle Brent formation was deposited in a deltaic to alluvial plain, Ness 1(N1) and lagoon to lower delta plain, Ness 2 (N 2) environment. Thus sandstones are inter-bedded with clay and coal. In general, Ness 1 unit has poorer petrophysical characteristics than Ness 2 unit and its oil-bearing leg is much lower especially to the East of the reservoir. The Upper Brent was deposited in a prograding lower shoreface environment. Three different types of sandstone are identified. At the top Tarbert 3 (T3) are massive sands with very good reservoir characteristics. This is the main oil bearing unit in the Brent East reservoir. Below Tarbert 2 (T2), there are mica-rich sandstones with lower permeability. These mica-rich sandstones exhibit a high natural radioactivity. The base of the Tarbert formation, Tarbert 1 (T1), is very similar to the top sandstone. Despite its lower average permeability, Tarbert 2 unit is not considered as a permeability barrier.
  19. 19. Page | 9 Figure 7: Depositional Setting of the Brent group 2.3 Summary To summarize, Tarbert can be described as massive shore face sands with excellent petro-physical properties, well connected throughout the field and may be even regionally, communicating partially with Upper Ness fluviatile system which is isolated from Lower Ness. Base Brent Etive and Rannoch are better quality reservoirs, but mainly water bearing in Brent East Block. Considering the small oil content in Ness 1, this unit is neglected in the reservoir model. Thus, the reservoir model focuses on the Ness 2 and Tarbert 1, 2 and 3 units. The Brent East reservoir of Alwyn North was characterized using data from two of the original vertical appraisal wells (3/9A- 2, 3/9A-4) and two new deviated delineation wells (N1 and N3). N3 characterized the northern part of the field where an important oil leg was confirmed mainly in the Tarbert units. N1 located to the West did not produce any oil and only encountered the aquifer, which does seem to be active. The water salinity in the reservoir is about 17,000ppm.
  20. 20. Page | 10 3 HYDROCARBON RESERVE ESTIMATION Reserves are estimated volumes of crude oil, condensate, natural gas, natural gas liquids, and associated substances anticipated to be commercially recoverable from known accumulations from a given date forward, under existing economic conditions, by established operating practices, and under current government regulations. Understanding the recoverable oil & gas reserves is important when trying to establish their present and future value. The definition of reserves takes into account the technical and commercial certainty of extraction using existing technology. 3.1 Types of Reserves The Society of Petroleum Engineers (SPE) categorizes reserves into two main types based on its degree of uncertainty using the current economic conditions including prices and costs and the available technology prevailing at the time of the estimate (see figure 8): 1) Proved Reserves; 90% certainty of commercial extraction 2) Unproved Reserve; which is further divided as:  Probable Reserves, 50% certainty of commercial extraction  Possible Reserves, 10% certainty of commercial extraction. The range of uncertainty reflects a reasonable range of estimated potentially recoverable volumes for an individual accumulation or a project. In the case of reserves, this range of uncertainty can be reflected in estimates for - Proved reserves (1P), - Proved + probable reserves (2P), - Proved plus probable plus possible reserves (3P) scenarios. Other categories such as low estimate, best (or average) estimate, and high estimate are also recommended. Total Oil and Gas Resource UndiscoveredDiscovered
  21. 21. Page | 11 Figure 8: Resource flow chart 3.2 Basic Definition For a better understanding on estimating reserves, a few important terms require definition. 1) Original oil in place (OOIP) and original gas in place (OGIP): The total volume of hydrocarbon stored in a reservoir prior to production. Reserves or recoverable reserves are the volume of hydrocarbons that can be profitably extracted from a reservoir using existing technology. 2) Resources: reserves plus all other hydrocarbons that may eventually become producible; this includes known oil and gas deposits present that cannot be technologically or economically recovered (OOIP and OGIP) as well as other undiscovered potential reserves.
  22. 22. Page | 12 3.3 Methods of Estimating Reserves Estimating hydrocarbon reserves is a complex process that involves integrating geological and engineering data. Depending on the amount and quality of data available, one or more of the following methods may be used to estimate reserves: 1) Volumetric 2) Material balance 3) Production history 4) Analogy These methods are summarized in Table 2. Table 2: Reserve Estimation Methods S/N Method Application Accuracy 1 Volumetric OOIP, OGIP, recoverable reserves. Use early in life of field. Dependent on quality of reservoir description. Reserves estimates often high because this method does not consider problems of reservoir heterogeneity. 2 Material balance OOIP, OGIP (assumes adequate production history available), recoverable reserves (assumes OOIP and OGIP known). Use in a mature field with abundant geological, petrophysical, and engineering data. Highly dependent on quality of reservoir description and amount of production data available. Reserve estimates variable. 3 Production history Recoverable reserves. Use after a moderate amount of production data is available. Dependent on amount of production history available. Reserve estimates tend to be realistic. 4 Analogy OOIP, OGIP, recoverable reserves. Use early in exploration and initial field development. Highly dependent on similarity of reservoir characteristics. Reserve estimates are often very general. The volumetric method is discussed in the next section.
  23. 23. Page | 13 3.3.1 Volumetric Estimation Volumetric estimates of HCIIP are based on a geological model that geometrically describes the volume of hydrocarbons in the reservoir. However, due mainly to the decrease in temperature and pressure from the reservoir to the surface, dissolved gases in oil evolves and expands at the surface thereby occupying larger volume in stock tanks. This necessitates correcting subsurface volumes to standard units of volume measured at surface or stock tank conditions. The basic volumetric equation (in field units) used is: 𝑂𝐼𝐼𝑃 = 7,758𝐴ℎ𝛷(1 − 𝑆 𝑤)/𝐵 𝑜𝑖 (1) 𝑂𝐺𝐼𝑃 = 43,560𝐴ℎ𝛷(1 − 𝑆 𝑤)/𝐵 𝑔𝑖 (2) Where; OIIP = Oil Initially in Place (STB) OGIP = Gas Initially in Place (SCF) A = Area of reservoir (acres) obtained from map data h = Height or thickness of pay zone (ft) obtained from log and/or core data 𝛷 = Porosity obtained from log and/or core data 𝑆 𝑤 = Connate water saturation obtained from log and/or core data 𝐵 𝑤𝑖, 𝐵 𝑔𝑖 = Formation volume factor for oil (reservoir bbl/STB) and gas (reservoir bbl/SCF) respectively at initial conditions from lab data; Recoverable reserves are a fraction of the OOIP or OGIP and are dependent on the efficiency of the reservoir drive mechanism. The basic equation used to calculate recoverable oil reserves is: 𝑅𝑒𝑐𝑜𝑣𝑒𝑟𝑎𝑏𝑙𝑒 𝑂𝑖𝑙 𝑟𝑒𝑠𝑒𝑟𝑣𝑒𝑠 ( 𝑠𝑡𝑏) = 𝐻𝐶𝐼𝑃 × 𝑅𝐹 (3) Where; RF = Recovery factor HCIIP = OIIP or GIIP The RF is dependent on the method of recovery used in producing the hydrocarbon. It is the sum of the primary and secondary recovery. The primary recovery factor is estimated from the type of drive mechanism. The secondary recovery factor, RFS, is given by:
  24. 24. Page | 14 𝑅𝐹𝑠 = 𝐸 𝐷 × 𝐸𝐴 × 𝐸𝑣 (4) Where;  ED = displacement efficiency  EA = areal sweep efficiency  EV = vertical sweep efficiency These efficiency terms are influenced by such factors as residual oil saturation, relative permeability, reservoir heterogeneity, and operational limitations that govern reservoir production and management. Thus, it is difficult to calculate the recovery factor directly using these terms. Other methods such as the decline curves are often applied.
  25. 25. Page | 15 4 METHODOLOGY 4.1 Overview of HCIIP Estimation The front-end activities that provided data and information used in determining the OIIP are summarized by the flow schematic in Figure 9. The approach taken to complete each activity is described in the sections following the figure. Figure 9: Hydrocarbon Initially in Place Estimation Process 4.2 Well logs Interpretation Logs data obtained from the various wells were analyzed for interpretation. . The purpose of interpreting the logs was to: Interpretation of Well Logs Calculation of Petrophysical properties (K, N/G, and ) Validation of Fluid Contacts Using RFT Estimation of Gross Rock Volume PVT Selection - Bo Estimation of HCIIP Well to Well Surface Correlations Identification of Reservoir Zones Identification of Fluid Contacts Quick-look Porosity Calculation Determination of formation Water Resistivity
  26. 26. Page | 16 a) Perform well to well surface correlations. b) Identify the reservoir rocks and obtain a number of physical parameters related to both its geological and petrophysical properties. Parameters obtained from this process are listed in table 3. c) Identify, characterize and quantify the fluids present in the reservoir rocks. Table 3: Properties Obtained from Reservoir Rocks S/N Parameters (Rock and fluid) 1 Lithology 2 Reservoir zones and thickness 3 Fluid contacts- water-oil, gas-oil and gas-water 4 Fluids present (oil, water and gas) and net pay zones 5 Resistivity 6 Porosity 4.2.1 Well to Well Surface Correlations Well to well correlation takes into account the various sand surfaces in each well with the isobaths reading for correlating the surfaces. It is a structured scheme to define reservoir architecture and quality and the relationships of the depositions in time. This is within the context of sequence stratigraphy. The correlations were done in both the North-South direction and the West-East directions crossing through faults and the wells as seen in figure 10. Figure 10: North-South direction and the West-East Directions of Correlations
  27. 27. Page | 17 Well to well correlation was also used to show the sequence stratigraphic surfaces (tops) of all the formations in the different wells in Alwyn North field. The stratigraphic top of well A4 was provided. Hence, all others wells were matched to those of well A4. The surfaces were identified based on a number of criteria which included the WUT, WOC, GOC gamma ray and resistivity. 4.2.2 Identification of Reservoir Zones and Thickness Reservoir zones were identified by identifying and eliminating areas considered as non- reservoir zones namely: - Shale - Tight formation - Salt - Coals The processes involved in identifying each are listed below. I. Shale - Presence of caving as observed from deviation between the caliper log and bit size. - Highly radioactive sections with gamma ray greater than 70 API. - No invasion: Low resistivity of less than 20 ohm-m and the resistivity readings are close to each other. - High Neutron values of 30%. - Large Neutron-Density separation. - Shale base line indicator from Spontaneous Potential readings. II. Tight formations - Caliper close to Bit size - Low Gamma Ray values of less than 30 API - High resistivity values of greater than 200 ohm-m and resistivity readings close to each other. - Density, Neutron, Sonic values close to matrix reference values. - Low Neutron and Sonic readings but high density readings
  28. 28. Page | 18 III. Other non-reservoir sections (salt, coal etc.) - Caliper close to bit size, but caving can be observed in Salt - Low gamma ray values for Halite and Anhydrite - Very high resistivity values The net thickness of the reservoir zones, uh are measured and recorded for each well. 4.2.3 Identification of Fluid Contacts - Water - Oil contact were identified using the resistivity overlay technique - Gas – Oil contact were identified using Density-Neutron separation (Gas effect) 4.2.4 Quick-look Porosity Calculation in Water, Oil and Gas Zones Porosity was calculated using the formula below: Oil and water zones: 2 DN   (5) Gas zones: 4 3 ND   (6) Where; N = Neutron Porosity reading D = Density Porosity reading 4.2.5 Determination of Resistivity of Formation Water Resistivity values were obtained from the LLD and LLS logs. LLD log represents the water resistivity in non-invaded zone while LLS log provided the resistivity of formation water in the flushed zone. Archie’s formula I and II was used in calculating the resistivity of water in the water zone and saturation of water in all the various reservoir zones. Rxo Rt RmfRw  (7) Where; Rw= Resistivity of formation water in the aquifer, Ωm Rmf = Resistivity of mud filtrate, Ωm Rt = Resistivity of non-invaded zone, Ωm Rxo= Resistivity of flushed zone, Ωm
  29. 29. Page | 19 Computation of fluid saturations in various zones: n t w mw R R S a   (8) whc SS  1 Where: wS = Water saturation, s.u hcS = Hydrocarbon saturation, s.u Rt = Resistivity of non-invaded zone, Ωm  = Porosity, p.u m = cementation factor = 2 for clean sandstone n = saturation exponent =1 for clean sandstone NB: it is assumed that the formation sandstones are clean for Archie’s formula to be applicable. Resistivity of formation water is calculated using Archie’s formular (equation (8)). Saturation of water is 1. Rt is read off from the logs. 4.3 Validation of Fluid Contacts Using RFT The Repeat Formation Tester (RFT) was used to validate the fluid contacts obtained from the well logs. Formation pressure changes vertically with depth as the fluid in the wellbore changes. The change in the pressure gradients is the basis for determining free water level (FWL) in the wellbore. The formation pressure versus depth data was received for well A-2, A-4 and N3. Procedure - Formation pressure was plotted against TVDSS for each well. - The depths where the characteristic pressure gradient changes were recorded Assumption: The OWC may vary from the FWL. However, it is assumed that the FWL=WOC.
  30. 30. Page | 20 4.4 Calculation of Petrophysical Properties 4.4.1 Net-to-Gross ratio, GN / This is the ratio of the net pay thickness (corresponding to the net pay zone) to the gross sand thickness of a geological unit. It was obtained using equation 5 below. t u h h GN / (9) Where; uh = Net pay thickness th = Gross sand thickness Net pay zones cut-offs are assigned based on the following: - Oil saturation greater than or equal to 0.3. - Reservoir thickness greater than 1m - Porosity greater than 1% - Permeability values greater than 1mD. 4.4.2 Average Porosity The thickness weighted average porosity equation was used in obtaining the average porosity over the net reservoir zones. For each geological unit, the average porosity Φ is given by:   ui ui h hΦ Φ i (10) Where; iΦ = porosity of each sub-reservoir units in the geological unit uih = thickness of the sub-reservoir unit 4.4.3 Average Initial Water Saturation Like the porosity, the average initial water saturation, wiS for each reservoir zones in a geological unit is given by:
  31. 31. Page | 21   ui ui hΦ hΦ i iwii wi S S (11) Where; wiiS = porosity of each sub-reservoir units in the geological unit uih = thickness of the sub-reservoir unit iΦ = porosity of each sub-reservoir units in the geological unit 4.4.4 Determination of Absolute Permeability The absolute permeability for each sand layer was estimated using the permeability- porosity data for each sub-reservoir unit (see sample Annex 1 document in figure 11). The value of average porosity obtained from section 4.2.4 was used to read off the permeability in each case. Figure 11: Sample Phi-K for Unit N1 4.5 Gross Rock Volume (GRV) Estimation GRV is the volume enclosed by the top and bottom surface of a reservoir and above the water contact. The GRV of Alwyn North was estimated using the traditional depth-area- thickness (DAT) method. Table 4 is the depth-area-thickness data received for tops of T3.
  32. 32. Page | 22 Table 4: Depth-Area data for Tarbert 3 S/N Depth (Top of T3) (m3 ) Area (Km2 ) 1 3,120 0.06 2 3,140 0.73 3 3,160 2.09 4 3,180 3.32 5 3,200 5.77 6 3,220 8.91 7 3231 11.33  The non-eroded zone occupies 55% of the total area. 4.5.1 DAT Procedure (Non-Eroded Zone) - The depths of surfaces T2, T1, N2 and N1 corresponding to each given depths of T3 were calculated. 𝑍 = 𝑍𝑜 + 𝑡ℎ𝑖𝑐𝑘𝑛𝑒𝑠𝑠 𝑜𝑓 𝑏𝑒𝑑 𝑎𝑏𝑜𝑣𝑒 𝑍 (12) Where; 𝐷( 𝑇3)= Depth (Top of T3) - The areas occupied for the eroded zone were calculated by: 𝑁𝑜𝑛 − 𝐸𝑟𝑜𝑑𝑒𝑑 𝐴𝑟𝑒𝑎 = 0.55 × 𝐴𝑟𝑒𝑎 (13) - The depths of all the surfaces were plotted against the non-eroded areas. - The volume occupied between two surfaces was estimated for each geological unit. 4.5.2 DAT Procedure (Eroded Zone) - The areas occupied for the eroded zone were calculated by: 𝐸𝑟𝑜𝑑𝑒𝑑 𝐴𝑟𝑒𝑎 = 0.45 × 𝐴𝑟𝑒𝑎 (14) - The depths of all the surfaces were plotted against the eroded areas. 𝑍 = 𝑍𝑜 + 𝐻𝑜−𝐻 2 (15) Where; 𝑍𝑜 = Depth (Top of T3) 𝐻𝑜 = thickness of bed when T2, T1, N2 or N1 from T3 𝐻 = thickness of bed when T2, T1, N2 or N1 from T3 is zero (see figure 12)
  33. 33. Page | 23 Figure 12: Eroded Surfaces 4.6 PVT Selection- Formation Volume factor, Bo The formation oil volume factor is a ratio that relates the volume of oil within the reservoir to the volume at standard conditions. The PVT study report (Annex 5-2 and Annex 5-3) provided contains the laboratory methods used in determining Bo on well A4 and N3 respectively. They are:  The constant composition study  The multi-stage separator or process test experiment  The differential vaporization experiment The reservoir fluid conditions temperature and pressure are 112o C and 445.5 bar respectively. For a better representation of Bo for the estimation of HCIIP, the composite Bo value drawn from the constant composition study and the process test experiment were used. Since the reservoir pressure is higher than the saturated pressure (270.1 bar), the composite Bo equation used is given by: 𝐵𝑜𝑐 = 𝑉(𝑃) 𝑉(𝑃𝑠𝑎𝑡) × 𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) (16) Where; 𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) = Formation volume factor of oil at saturated pressure 𝑉( 𝑃) = Volume of oil at reservoir pressure 𝑉( 𝑃𝑠𝑎𝑡) = Volume of oil at saturated pressure Because of the absence of a PVT study report for the other wells, it is assumed that the composite Bo for well A4 is same for all the other wells. 4.7 Estimation of HCIIP For an oil reservoir, the Oil Initially in Place (OIIP) is given by:
  34. 34. Page | 24 𝑂𝐼𝐼𝑃 = 𝐺𝑅𝑉 × 𝛷 × 𝑆𝑜 × 𝑁 𝐺 × 1 𝐵𝑜 (17) For a gas reservoir, the Gas Initially in Place (GIIP) is given by: 𝐺𝐼𝐼𝑃 = 𝐺𝑅𝑉 × 𝛷 × 𝑆𝑔 × 𝑁 𝐺 × 1 𝐵𝑜 (18) Where; 𝑆𝑜 = Oil saturation given by: = 1 − 𝑆𝑤 𝑆𝑔 = Gas saturation given by: = 1 − 𝑆𝑤 − 𝑆𝑜 4.7.1 Assessment of Reservoir Uncertainties Reservoir uncertainty is the variation of HCIIP in the range of possible outcomes. Every step taken in estimating the HCIIP, starting from the seismic interpretation, has a level of uncertainty attached to it. Hence, it is imperative that these uncertainties are taken into consideration before good developmental decisions are made. Geological uncertainties evaluation includes structural uncertainties and some dynamic uncertainties. 4.7.2 Estimating of HCIIP Uncertainties For this study, the deterministic method was used in estimating the HCIIP uncertainties. Three cases were considered namely: 1) Optimistic hypotheses analyzed for maximum case (P90) 2) Reasonable hypotheses analyzed for average case (P50) 3) Pessimistic hypotheses analyzed for minimum case (P10). The main geological uncertain parameters affected by these methods are structural uncertainties (GRV) and the static uncertainties (N/G, 𝛷, wiS ) Table 5: Uncertain Reservoir Estimation Cases Case Bed Thickness Porosity Water Saturation GRV
  35. 35. Page | 25 Maximum case Maximum value Maximum value Minimum value Maximum bed thickness Average case Average value Average Average value Average bed thickness Minimum case Minimum value Minimum value Maximum value Minimum bed thickness 5 RESULTS AND DISCUSSIONS 5.1 Introduction The following sections present the main results obtained from the determination of the HCIIP for the Alwyn North field. More comprehensive results can be found in the Appendix section of this report.
  36. 36. Page | 26 5.2 Well Logs Interpretation 5.2.1 Well to Well Surface Correlations (a) (b) Figure 13: Well to Well Correlation a) North-South and b) West-East Cross- Sections Figures 13 shows that there are many geological structures present in the formations of the Brent East Group such as tilted heavy faulting which is due to the deposition of the sandstone formation in the early Jurassic age and creating of the North Viking Graben. The WOC line gives a clear picture of the layers that are in the aquifer. The depths of the stratigraphic tops can be found in table 6a. Fault Eroded surface
  37. 37. Page | 27 5.2.2 Logs Interpretation- Identification of Reservoir Zones (a) (b)
  38. 38. Page | 28 (c) (d) Figure 14: Sections of Interpreted Well Logs for Well a) A4 b) A2 c) N1 and d) N3 The green shadings indicate non-reservoir zones such as shale and micaceous. Red shading indicates the non-shaly and non- micaceous layers. T3 are massive sands with very good reservoir characteristics. This is the main oil bearing unit in the Brent East reservoir. In T2, there are mica-rich sandstones with lower permeability. These mica-rich sandstones exhibit a high natural radioactivity. Ness 2 formation is characterized by numerous intercalations of shale, mudstones, coal and sandstones. At a depth of about 3,120m, there is an observed deviation of RHOB, NPH curves indicating a change in formation fluid, thereby confirming a WOC. This value conforms to 3,231m stated in the given data. In N1, the resistivity and density is almost constant. Since it is below the identified WOC, it can thus be concluded that this formation is an aquifer. Hence it does not contribute to the OIIP estimate.
  39. 39. Page | 29 Ness 1 unit has poorer petrophysical characteristics than Ness 2 unit and its oil-bearing leg is much lower especially to the East of the reservoir. No GOC was observed. 5.2.3 Resistivity and Saturation of Formation Water in the Aquifer (Formation N1) In the water region, the saturation is assumed to be 1 as it the region was majorly water. Using equation (8), the resistivity of water in the aquifer was estimated as 0.126. See Appendix II for detailed calculations. The average resistivity and saturation values for all zones are listed in the attached excel file in Appendix III. 5.3 Validation of Fluid Contacts Figure 15: Pressure gradient curve for wells A4 and N3 The pressure- gradient curves of wells A4 and N3 indicated a change in gradient. The region with the higher gradient of 17.11bar/m is the oil and the lower gradient of 9.32 bar/m indicates water. WOC
  40. 40. Page | 30 The pressure gradient changes at a depth of about 3,232.5m which indicates the WOC. The WOC depth is approximately equal ad hence validate the WOC obtained from logs. 5.4 Petrophysical Properties and Net to Gross Ratio Table 6a: Petrophysical Properties (Porosity, Saturation, N/G, Stratigraphic Tops) The table above shows some of the results obtained from the well to well correlations exercise: the top of the bed layers to be precise. In all the wells, T3 have the highest reservoir thickness with good petrophysical characteristics i.e. high porosity (between 22.59 – 26 p.u) and highest oil saturation. This makes it the bed with the highest oil leg. This is due to its high permeability as indicated by the permeability data. Because N1 is an aquifer with no reservoir, its thickness does not contribute to the overall estimation of OIIP. Its water however will provide natural drive that will be useful during production.
  41. 41. Page | 31 Table 6b: Petrophysical Properties (Absolute Permeability) Table 6b shows the average permeability for each layer. The permeabilities range from 50-2600 mD. T3 and N2 showed similar permeability. T2 and T1 have equal lower permeability of 50 mD mainly due to the presence of micaceous sandstones. The base of T2 and top of T3 has similar permeability of 300mD. Despite its lower average permeability, T2 unit is not considered as a permeability barrier. 5.5 GRV Estimation 1) Minimum Case (a) (b) Figure 16: Minimum case depth-area plot a) non-eroded zone and b) eroded zone
  42. 42. Page | 32 Table 7: Summary of Minimum GRV Sand Sand GRV Total Sand GRV Non- Eroded Eroded T3 160,000,000 7,200,000 167,200,000 T2 16,000,000 3,600,000 19,600,000 T1 0 0 0 N2 48,000,000 31,200,000 79,200,000 Total Minimum GRV 266,000,000 2) Average Case (a) (b) Figure 17: Average case depth-area plot a) non-eroded zone and b) eroded zone
  43. 43. Page | 33 Table 8: Summary of Average GRV Sand Sand GRV Total Sand GRV Non- Eroded Eroded T3 194,500,000 206,500,000 206,500,000 T2 18,000,000 27,800,000 27,800,000 T1 7,000,000 11,800,000 11,800,000 N2 17,000,000 69,000,000 69,000,000 Total Average GRV 315,100,000 3) Maximum Case (a) (b) Figure 18: Maximum case depth-area plot a) non-eroded zone and b) eroded zone Table 9: Maximum GRV Sand Sand GRV Total Sand GRV Non- Eroded Eroded T3 220,000,000 11,200,000 191,200,000 T2 40,000,000 16,000,000 44,000,000 T1 12,000,000 12,800,000 20,800,000 N2 4,000,000 59,200,000 63,200,000 Total Maximum GRV 319,200,000
  44. 44. Page | 34 Figures 16 – 18 gives a clear picture of formations that have some of its thickness below the WOC. In all cases, T3 was above the WOC. The GRV was calculated only for the parts of the reservoir above the WOC. Again, T3 has the highest GRV due to it having the highest bed thickness above WOC. 5.6 PVT Selection- Formation Volume factor, Bo The composite Bo was calculated are 1.6614 and 1.5 for well N3 (See Appendix I for detailed calculation). The variation in their results is due mainly to the variation in the conditions under which the experiments were conducted. Table 10 contains the major differences between each study that may have contributed to the differences in the composite Bo.. Table 10: Differences in the PVT Study for Wells A4 and N3 S/N Well A4 Well N3 1 Study was conducted in 1980 Study was conducted in 1987 2 Three-stage process condition separation test was conducted. Two-stage process condition separation test was conducted. The composite Bo was chosen for the calculation of the OIIP due to the following reasons: 1. Because well A4 was drilled before N3, the PVT result gives more representation of the reservoir oil in its original state. 2. 3-stage separation gives better separation than the two stage separation. hence, a better value of Bo. 5.7 Estimation of HCIIP Including Uncertainties 1) Minimum Case (P10) Table 11: Summary of Results (Minimum Case)
  45. 45. Page | 35 2) Average Case (P50) Table 12: Summary of Results (Average Case) 3) Maximum Case (P90) Table 13: Summary of Results (Maximum Case)
  46. 46. Page | 36 6 CONCLUSION HCIIP estimation is the cornerstone of and exploration and production process. Before effective developmental decisions can be made, it is necessary that uncertainties in estimating the HCIIP are taken into consideration at every step of the process. The Volumetric method was used to estimate the HCIIP for Alwyn North field. Five parameters were obtained namely: 1) Gross rock volume obtained from DAT data and well fluid contacts 2) Net to Gross obtained from well logs 3) Porosity obtained from well logs 4) Oil/Gas saturation obtained from well logs and 5) FVF obtained from PVT analyses To account for uncertainties in estimating the reserve, three cases were considered; 1) Minimum case (P10)- lowest OIIP 2) Average case(P50)- average OIIP 3) Maximum case (P90)- highest OIIP The following conclusions were drawn during and after estimating HCIIP; 1) Alwyn North field Brent East is an oil field with no gas cap. 2) The geological structures showed the presence of two faults and some tilted folds. 3) The WOC was consistent at about 3,231m showing that the reservoir is continuous and connected and there is a high likelihood that the faults are non-sealing. 4) Tarbert 3 has the highest reservoir thickness with the best reservoir petrophysical characteristics (permeability, oil saturation and porosity) making it the most contributor to the estimated reserve. Tarbert 2 has a lot of mica embedded in its sandstones. All the wells had about the same WOC Ness 1 was in the aquifer zone and could not be produced from. 5) The OIIP of the field was found to be : Minimum case = 19,253,824.44 m3 Average case = 31,421,555.11 m3 Maximum case = 39,837,677.39 m3
  47. 47. Page | 37 T3 is the largest contributor to the OIIP in the field due to its high porosity, high reservoir thickness and low water saturations.
  48. 48. Page | 38 REFERENCES 1) http://www.spe.org/index.php 2) Owil N (2018): Lecture Note: Hydrocarbon‐ In‐ Place Estimation. March 5‐ 9, 2018 – IPS
  49. 49. Page | 39 APPENDIX Appendix I: Resistivity and Saturation of Formation Water in the Aquifer (N1) In the water zone Sw= 1 (obtained from logs), Rt = 4Ωm, up.16 , m =2, n =1, a =0.81 Assuming the sandstones is clean, From equation (8), mw w a R R  2 16.0 81.0 4 x 126.0 Appendix II: Calculation of FVF 𝐵𝑜𝑐 = 𝑉(𝑃) 𝑉(𝑃𝑠𝑎𝑡) × 𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) (16) 𝐵𝑜𝑝 = 𝑉𝑜 𝑉𝑠𝑐 = 𝑉(𝑃) 𝑉𝑠𝑎𝑡 × 𝑉𝑠𝑎𝑡 𝑉𝑠𝑐 (19) For well A4 @ reservoir conditions (112.1℃ and 445.4 bar(g)) 𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) = 1.711 𝑉𝑜 𝑉𝑠𝑎𝑡 = 0.9571 𝐵𝑜𝑐 = 0.9571 × 1.711 = 1.6376 For well N3 @ reservoir conditions (111℃ and 445 bar(g)) 𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) = 1.664 𝑉𝑜 𝑉𝑠𝑎𝑡 = 0.955 𝐵𝑜𝑐 = 0.955 × 1.664 = 1.589 Appendix III: Data Sheets Obtained During Calculation 1. Excel Spreadsheet (HCIIP Estimation) 2. Well-to-Well Correlation
  50. 50. Page | 40 Table 14: Well to Well Correlation Data Sheet a) North- South b) West- East (a) (b) 3. Depth-Area Data Table 15: Depth-Area Data Sheet a) Non-eroded b) Eroded
  51. 51. Page | 41 a) b) 4. Petrophysical Properties Data Sheet Table 16: Petrophysical Properties Data Sheet
  52. 52. Page | 42

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