Introduction
For the five practical classes that form this course on hydrocarbon resources you will be working on a single project that develops on a week-by-week basis. Hence, these practical class handouts form an integrated workbook rather than a series of stand-alone handouts. Important: you will need to bring your workbook and all of your associated work to each class as you will need to refer back to it in subsequent practical sessions. You will also need a calculator and coloured pencils for each practical.
Course aim
The aim of this series of practical sessions is to provide grounding in the techniques routinely used by geologists working in the exploration sector of the hydrocarbon industry in their search for oil and gas reserves. Specifically, you will work on a project that follows the standard workflow undertaken in the hydrocarbon industry and each week will focus on a particular stage in the exploration process: (i) frontier exploration and initial discovery, (ii) determination of source rock quality and depth of burial, (iii) determination of bulk reservoir volume, (iv) reservoir modelling to determine likely net volume, and (v) determination of recoverable reserves. By the end of the course, you should be aware of the various methods used by geologists and have an understanding of the way in which these methods are implemented. This course provides a hands-on approach to solving problems related to hydrocarbon exploration and by its end you will have the experience and skills required to undertake more advanced applied modules in later parts of your degree.
Assessment
The final practical in this course will be assessed. Importantly, because these practical classes form an integrated series, you will need to have completed the first four practical assignments in order to successfully undertake the fifth one. Further details of weighting of this assessment and on the form and weighting of the formal exam taken at the end of this module are given in the Module Catalogue description.
Background
You have gained employment as an exploration geologist with Megabucks Oil, one of the world's leading hydrocarbon companies that specialises in exploration in frontier provinces. Keen to impress your new boss, you have taken on an assignment to head-up an asset team working in the remote country of Utopesia, the government of which has invited Megabucks Oil to reassess and develop its fledgling state-owned efforts relating to the search for oil and gas reserves. As part of this process you have been given access to some old 2D seismic data, to data from 3 wells drilled in the 1980s, and to some rather limited biostratigraphic data, none of which looks especially promising.
There is no doubt that the task ahead is going to be difficult but the potential rewards could be enormous, not least because your boss has promised you a healthy bonus if you can discover a viable oil or gas reserve.
Week One: Chronostratigraphic Interpretation
Aim
The aim of this practical exercise is to gain awareness of the relationship between space and time in sedimentary successions. In particular, you will learn how to convert from the spatial to the temporal domain through the construction of a chronostratigraphic diagram and you will interpret a relatively simple dataset to determine rates of sedimentation and make stratigraphic predictions related to hydrocarbon exploration.
Background
You are provided with a line interpretation from a solitary 2D seismic line (Line 1) of 1980s vintage, the location of which is shown on the map of the coastal and offshore region of Utopesia (Figs. 1.1 & 1.2). Major reflections on the line interpretation identify several stratigraphic sequences and your task is to determine the occurrence and duration of any major sequence boundaries and to identify possible sites of reservoir sand accumulation, especially those that might be capped by shale lithologies which could act as a seal.
Tasks
1. Figure 1.2 depicts the line interpretation of Seismic Line 1, and shows the geometry of the major seismic reflectors from the northern part of the basin.
a. Identify and label on Fig. 1.2 the types of reflector terminations. Use the information in Figs. 1.3, 1.4 and 1.5 to help you with the terminology.
b. Using a numbering system (1, 2, 3, 4...), indicate on Fig. 1.2 the relative age of each reflector from oldest to youngest.
c. On Fig. 1.6 construct a chronostratigraphic diagram using arbitrary time units. Use the procedure in Fig. 1.7 to help you achieve this.
d. Mark the positions and types of reflection terminations on your chronostratigraphic diagram. This is important because spatial significance is otherwise not evident.
e. Colour code the depositional sequences and identify periods of non-deposition and/or erosion.
2. Encouraged by your chronostratigraphic interpretation of Seismic Line 1, your boss at Megabucks Oil has given the go-ahead to purchase data from three exploration wells that were drilled at localities A, B and C (Figs. 1.1 and 1.2) in the 1980s by a rival company who no longer operates in the area. These data reveal the biostratigraphic age information given in the accompanying table (see seismic section interpretation in Fig. 1.2 for depth locations).
a. On Fig. 1.8 construct a revised chronostratigraphic diagram using this new absolute age data. The easiest way to do this is to write the ages of individual units on the original seismic line interpretation. For those units of unknown age use interpolation (averaging) to estimate their age (hint: they should fit conveniently into multiples of
2.5, 5, 10 or 25 Myr). Next, draw a new chronostratigraphic diagram on Fig. 1.8 using a suitably revised absolute scale for the time axis.
b. Compare your new chronostratigraphic diagram with the original. Make notes on Fig. 1.8 and in the box below to explain how the shape of the non-depositional and erosional hiatuses has changed. In the box below comment on what this means about the presence of time gaps in the stratigraphic record.
c. Plot the position of each well on your revised chronostratigraphic diagram in Fig.
1.8. For each well, calculate the proportion of time characterised by active deposition as opposed to non-deposition/erosion; write your answers in the box below.
d. Note from the original interpreted seismic section (a depth-depth plot) that the thickness of the drilled succession in each well is the same, but you know from the revised chronostratigraphic diagram that the time encompassing deposition at each well was different. In the box below, write notes to explain what this implies about rates of sedimentation. Calculate rates of sedimentation (m/Myr) for the stratigraphic intervals in each well; write your answers in the box below.
3. Based on your chronostratigraphic interpretation, write notes on Fig. 1.8 to explain the likely occurrences of sand-rich intervals which might make potential reservoir units. Think in terms of the processes which transport sand from coastal and shallow marine (proximal) areas to deep marine basinward (distal) areas and where within such a system sand is likely to accumulate. How might finer-grained facies that could potentially act as a seal become juxtaposed on top of coarser-grained units?
Specifically, think how relative sea level changes cause the juxtaposition of such facies. The tutor will lead a discussion session that will help answer these questions.
(20 mins)
Encouraged by your chronostratigraphic interpretation of the old 2D seismic data, your boss at Megabucks Oil has commissioned a new 3D seismic survey for the central part of the basin. From this new survey, Line 2 has the best structural development (Figs. 1.1 & 1.9).
4. Colour in the major reflectors seen in Seismic Line 2 (Fig. 1.9) and mark on any prominent reflector terminations. Specifically, identify the likely boundaries between the units named A-D on the section. Based on the lithologies of these units and the style of structural development, highlight areas that might make potential hydrocarbon traps. Justify your interpretation by making notes in the box provided on Fig. 1.9.
(20 mins)
Week Two: Source Rock Burial History and Thermal Maturity
Aim
The aim of this practical exercise is to demonstrate how the porosity of a lithological unit varies with depth as a result of mechanical compaction and how the history of burial of a unit can be determined by applying a decompaction routine. Additionally, this practical will demonstrate how the subsurface geothermal gradient dictates the depth of the oil and gas windows within which kerogen begins of crack to generate hydrocarbons.
Background
Encouraged by your chronostratigraphic interpretation of the old 2D seismic (Line 1) and the promising structural development revealed by the new 3D seismic survey in the central part of the basin (Line 2), your boss at Megabucks Oil has agreed to extend the 3D seismic survey into the southern part of the basin. In this newly explored region, the most promising structural development is seen in Line 3, for which a line interpretation is provided on the accompanying sheet (Fig. 2.1). Additionally, several of the major rock units crop out at the surface in the south-western part of the basin. You undertake a field- based study in this area and discover an oil shale (Unit D) with 5% Total Organic Carbon (TOC). This is overlain by Unit C, a fluvial sandstone with good preserved porosity and Unit B, a relatively impermeable non-marine shale of apparent fluvial floodplain origin. Several of the essential elements for a petroleum play are present: source rock, reservoir rock, seal rock. Encouraged by this, your company decides to drill a new exploration well (Well D) in the vicinity of Line 3.
Tasks
1. List 4 reasons why the site of Well D shown on Fig. 2.1 might be a good drilling locality. Why might you expect to find a petroleum play here?
Drilling commences and after 5 weeks Well D has reached a depth of 4.1 km. Units B, C and D have all been penetrated but only a residue of ‘dead' oil coating the grains within the supposed reservoir unit was found. Despite this obvious setback, the well has provided important information about the subsurface geology in the basin. This includes thickness and biostratigraphic age information for each rock unit (Fig. 2.2). In addition, newly acquired regional structural data indicates that this part of the basin was uplifted (inverted) by 2 km between 20-10 Ma. This suggests that 2 km of former basin fill was eroded at this time and explains the presence of the unconformity between units A and B seen on Seismic Line 3 (Fig. 2.1).
2. Why do you think the well was dry, despite the presence of a favourable anticlinal trap structure? List up to 6 reasons. How might the faults in the eastern part of the basin have influenced seal integrity?
Given the porosity and temperature data recovered from Well D (Figs. 2.3 and 2.4), you now have enough information to reconstruct the burial history of the basin. To generate the burial history plot you need to work back through time, successively removing each layer. The explanation for this decompaction procedure is outlined in Figs. 2.5 to 2.8. You will need to decompact each layer as its position within the sediment column varies. You can predict the new porosities for each layer at its new burial depth by using the porosity-depth curves in Fig 2.3 (note that different lithologies compact at different rates).
3. Reconstruct the burial history of the basin fill by calculating the former thickness and porosity of each depositional unit back through time. A blank burial history template is provided in Fig. 2.9; you simply need to work out the numbers.
4. On Fig. 2.10 plot a graph of the depth of burial of the various rock units over time (i.e. a burial history plot).
5. What was the maximum burial depth of source rock D? When did maximum burial occur? Label these values on Fig. 2.10.
6. Use Fig. 2.4, which depicts the geothermal gradient (change in temperature with depth), together with your burial history graph to determine both the depth and the time at which source rock D first exceed the 130oC isotherm (the temperature at which oil begins to be generated). At what depth and time did source rock D first exceed the 150oC isotherm (the temperature at which gas begins to be generated)? At what time did source rock D cease generating petroleum? What assumptions do these calculations make about the geothermal gradient? Indicate your answers in the box below.
7. For the petroleum generated by the source rock to be expelled, the pore spaces within the source rock must be larger than the hydrocarbon molecules. A minimum source rock porosity of 10% is required in order for petroleum to escape. Would the petroleum have been expelled from the source rock? Indicate your answer in the box below.
8. Of the petroleum generated and expelled, what proportion would have been oil and what proportion would have been gas? Indicate your answer in the box below.
Studies of source rock composition indicate that conversion of the total organic carbon to petroleum would occur at a constant rate equivalent to 2.5% per Myr (i.e. complete conversion after 40 Myr). For the source rock in this basin to be viable, reservoir engineers have calculated that at least 50% of the Total Organic Carbon (TOC) must be converted to petroleum.
9. On the basis of your burial history graph in Fig. 2.10, what proportion of the TOC in the source rock has been converted to petroleum. Based on this calculation, is the petroleum play potentially viable? Indicate your answer in the box below.
10. Given that the reservoir unit within the anticlinal trap structure penetrated by well D was barren, indicate where else on Seismic Line 3 (Fig. 2.1) any migrating petroleum fluids might have become trapped to form an oil- and gas-filled reservoir. In the box below, list the possible hydrocarbon trapping mechanisms that exist elsewhere in the region based on observed relationships in Seismic Line 3.
Week Three: Determination of Bulk Reservoir Volume
Aim
The aim of this practical is to gain understanding of the method used for contouring a complex spatial dataset and to use this information to determine the bulk rock volume of the hydrocarbon-filled part of a reservoir succession.
Background
Encouraged by your analysis of Source Rock D, your boss at Megabucks Oil decides to drill a prospect on the prominent anticlinal structure seen on Seismic Line 3 (Fig. 2.1). The plan is that Well E will have several side tracks. The first well (E-1) strikes both oil and gas and is quickly followed by a second (E-2) which strikes just gas. Wells E-3 and E-4 again strike both oil and gas. Whilst this is a welcome success, it quickly becomes apparent that reservoir Unit C is considerably thinner than predicted. Closer inspection of core recovered from Well E1 reveals that only the uppermost 20 m of reservoir Unit C is acting as a reservoir because the remainder of Unit C has been subjected to secondary growth of calcite and/or clay within the pore spaces, effectively rendering the lower part of the unit impermeable in this region. Within the reservoir, the depth to the gas-oil interface is 2215.3 m, and the depth to the oil-water interface is 2252.9 m.
In order to establish the limits of the reservoir, your company decides to drill a total of 31 side-track test wells in order to identify the extent of the petroleum-filled part of the reservoir. Well locations are shown on the field map in Fig. 3.1. The depths to the top of the reservoir for each well are recorded in the table in Fig. 3.2. In addition, some wells have dipmeter information that records the dip amount and orientation of the bedding within the reservoir unit. These data are shown graphically on the field map (Fig. 3.1).
Tasks
1. On Fig. 3.1, use a PENCIL to mark on the depth to the top of the reservoir for each well location based on the data in Fig. 3.2.
2. For those wells that have dipmeter data, estimate the depth to the top of the reservoir 500 m horizontally away from the well in the true dip direction and mark these depths on Fig. 3.1. These will provide additional points with which to generate a more realistic contour map. The procedure for doing this is given in Fig. 3.3.
3. Using a PENCIL, produce a contour map on Fig. 3.1 for the depth to the top of the reservoir. Choose your contour interval carefully by considering the number of data points and the range of depth values. Note that the presence of a vertical fault in the western part of the prospect will mean that contours will be offset across the fault plane.
4. Mark on Fig. 3.1 the maximum extent of the gas accumulation within the reservoir.
5. Mark on Fig. 3.1 the maximum extent of the oil accumulation within the reservoir.
6. On the worksheet template in Fig. 3.5 construct a sketch cross-section from X-Y, marking on the top and base of the 20 m-thick reservoir, and the levels of the gas-oil and the oil-water contacts. What geological feature is acting to trap the hydrocarbons?
7. Using the data from your contour map in Fig. 3.1, construct an area versus depth plot for the reservoir using the template in Fig. 3.6. To do this, you will need to determine the area of reservoir that lies above a series of specified depths. See Fig. 3.4 for an example of how to achieve this.
8. Use your area versus depth plot to determine the bulk rock volume of gas-filled part of the reservoir (m3) and the bulk rock volume of the oil-filled part of the reservoir (m3). Show your working and write your answers in the calculation box in Fig. 3.6.
Week Four: Reservoir Modelling to Predict Sedimentary Architecture
Aim
The aim of this practical is to demonstrate the difference between gross reservoir (total volume) and net reservoir (volume with favourable porosity and permeability characteristics). Additionally, this practical will also provide grounding in the construction of a simple reservoir model with which to account for the geologic complexity of the reservoir unit.
Background
After determining the bulk rock volume of the reservoir, you are confident that the discovery is sufficiently large to store a commercially viable hydrocarbon reserve. However, the results of an externally commissioned report indicate that the reservoir interval is heterogeneous such that only part of it is effective for the storage of petroleum fluids. The report suggests that fluvial channel sandstones are forming effective net reservoir, whereas fine-grained fluvial overbank siltstones and claystones are too ‘tight' to form an effective reservoir. Within minutes of reading the report, your boss is on the phone and he wants you to build a reservoir model to quantify the likely net:gross ratio of the bulk reservoir volume and to determine the likely distribution of good quality net reservoir within the overall bulk rock volume. The exploration contract is up for renewal and there is no time to build a sophisticated model, so you decide to opt for a simple approach.
Tasks
1. Core recovered from Well E-1 has been examined and a graphic core log is provided in Fig. 4.1. Can you recognise any commonly repeating cycles in the log? What characteristics define the base of each cycle and the nature of the internal fill? Specifically, make notes in the interpretation column of Fig. 4.1 regarding the occurrence of coarser-grained versus finer-grained facies within each cycle.
2. Structurally restored dipmeter data portraying the azimuths of cross bedding foreset dip directions are also provided on Fig. 4.1. What does the distribution of data suggest about the variability of the palaeoflow direction? What type of fluvial system might this indicate? Write your answer directly on fig. 4.1.
3. Based on your interpretation of the well log in Fig. 4.1 you begin looking for modern fluvial systems which might be suitable as an analogue with which to understand the complexity inherent in the reservoir. Fig. 4.2 is an infra-red aerial photograph of a meandering fluvial system from Alaska. Annotate the image to highlight the main architectural elements within the system (e.g. active and abandoned channels, point bars, floodplain lakes). Next, indicate with a series of arrows the migration direction of various reaches of channel. Given that sandstones are deposited from the channels as they migrate, highlight likely regions of sand-grade sediment accumulation. Given that siltstones and mudstones are deposited in extra-channel overbank and abandoned channel areas, highlight likely regions of fine-grained sediment accumulation.
4. You are now starting to understand how the stacking of mud versus sand within fluvial systems might impact on the quality of fluvial reservoirs but you want to learn more so you call in the experts from "Mountney Earth Science Consulting". Watch the video provided by the tutor, snapshots from which are shown in Fig. 4.3. The video shows how meandering fluvial systems migrate laterally and eventually avulse. You learn that four important variables which act to control the architecture of fluvial systems are: (i) the width and depth of the channel, (ii) the rate of lateral channel migration, (iii) the avulsion frequency, and (iv) the rate of subsidence.
You are now ready to build a simple 2D model of the reservoir. The model template depicted in Fig 4.4 portrays a cross-sectional view of a fluvial system that flows through a two kilometre wide fault-bounded graben system which is thought to be present in the centre of the reservoir interval. Subsidence on the basin bounding faults is considered to have been responsible for enabling the vertical accumulation of the fluvial deposits that make up the reservoir interval. The well log (Fig. 4.1) suggests that the fluvial channels were 10 m deep, and modern analogue studies show that channels of this size avulse (jump position) on average once every 100 years in response to major flooding events. The model in Fig. 4.4 depicts 4 such events (TA-TD). Your task is to simulate further avulsion events by applying some simple rules to this model. Some aspects of sedimentary system behaviour are intrinsically random (e.g. channel avulsion), and hence the modelling process utilises an element of randomness such that the results of every model simulation will be slightly different. This stochastic modelling approach is a standard way of modelling natural systems and is routinely used in reservoir modelling. To prepare your model, determine values and complete the boxes in Fig 4.5. Detailed instructions are provided below and a simplified set of instructions are provided in Fig. 4.6.
1. Assume that subsidence creates accommodation space (space for deposition) at a rate of 0.05 m/yr and that the channels avulse every 100 years. The model will step through a series of 15 time steps each representing 100 years of evolution.
2. Following each avulsion event, determine the number and position of new channels using the random number generator (RAN# button) on your calculator. 0-0.333 signifies the creation of 1 large channel (150 m wide), 0.334-0.666 signifies the creation of 2 medium sized channels (each 75 m wide), and 0.667-0.999 signifies the creation of 3 smaller channels (each 50 m wide). All channels are 10 m deep.
3. Next, determine the position of your new channel(s). Again, use your random number generator. 0.1 = a position 10% of the way across the 2 km-wide basin floor (i.e. 0.2 km from the western bounding fault), whereas 0.2 = a position 20% of the way across the 2 km-wide basin floor (i.e. 0.4 km from the western bounding fault). Perform a new random number selection to locate each channel if you have more than one.
4. Next, determine the direction in which each channel migrates laterally. Again, use your random number generator. 0-0.499 signifies channel migration to the west; 0.5-0.999 signifies channel migration to the east.
5. Next, determine the rate of lateral migration. Again, use your random number generator. 0-0.333 signifies slow lateral migration rate of 0.5 m/yr such that a channel migrates 50 m over a 100 year time step. 0.334-0.666 signifies moderate lateral migration rate of 1 m/yr such that a channel migrates 100 m over a 100 year time step. 0.667-0.999 signifies fast lateral migration rate of 3 m/yr such that a channel migrates 300 m over a 100 year time step.
6. Draw on your new channel configurations for 5 avulsion events (i.e. simulate 500 years of evolution with one avulsion every 100 years & subsidence of 5 m after each avulsion event; these intervals represent time steps 1-5 in your model run).
7. For the following 500 years (time steps 6-10), the faults are inactive and the subsidence rate is zero. However, the channels still avulse and take up new ‘random' positions on the floodplain and they still migrate laterally. How does this affect the degree to which channel sandstone bodies are laterally connected?
8. For the following 500 years (time steps 11-15), the faults generate subsidence at a rate of 0.1 m/yr. How does this affect the degree to which channel sandstone bodies are inter-connected?
9. Make notes on Fig. 4.4 to explain how subsidence controls the stacking of good quality (channel sandstone) reservoir.
Week Five: Determining Net:Gross, Estimating Recoverable Reserves and Evaluating Risk
Aim
The aim of this practical is to gain experience in the description and interpretation of core, thin sections and well logs for the purpose of quantifying net reservoir porosity, which is crucial for determining the viability of a reservoir unit. Additionally, consideration will be given to the quantification of uncertainty in predicting likely net recoverable hydrocarbon reserves.
Background
The results of your reservoir modelling study have convinced your boss at Megabucks Oil that there still might be sufficient net reservoir for the field to be viable. The final stage of the field evaluation process requires a detailed study of the key net reservoir facies so as to determine their relative proportions, porosity, permeability and degree of hydrocarbon saturation. Tests of five wells within central part of the field have demonstrated that they are in pressure communication with each other and indicate that the upper 10 m of the reservoir is likely formed by the lateral amalgamation of overlapping fluvial channel elements with probable geometries similar to those predicted for time steps 6-10 in your reservoir model. Lower parts of the reservoir are more clay dominated with only limited sandbody interconnectivity, as predicted by time steps 1-5 in your reservoir model. Time steps 11-15 in your model represent the lower part of the overlying claystone-dominated seal or cap rock unit (see Fig. 4.4).
Tasks
1. Study the fluvial facies model for a meandering river system in Fig. 5.1. Use this and the results of your 2D reservoir model in Fig 4.4 to produce a qualitative sketch of the likely 3D facies architecture in the reservoir for time steps 1-5, 6-10 and 11-15, as predicted by your model. A template to do this is provided in Fig. 5.2.
2. Use the results from your 2D reservoir model combined with your qualitative 3D facies models to estimate the ratio of preserved channel to overbank facies for: (i) the uppermost 10 m of the reservoir (as represented by your 3D sketch for time steps 6-10 in Fig. 5.2) and (ii) the reservoir interval lying immediately beneath this (as represented by your 3D sketch for time steps 1-5 in Fig 5.2). Write your answers on Fig. 5.2.
3. Remember from Practical 3 that only the uppermost 15 m of Unit C is acting as effective reservoir because calcite cement and clay growth has destroyed porosity and permeability in underlying parts. Given this, estimate the proportion of channelised versus floodplain elements for the uppermost 15 m of the reservoir interval.
Estimate ratio of Channel sandstone to Floodplain claystone:
Within the cored wells, four lithofacies types are identified (Figs. 5.3 and 5.4). These are:
(i) facies A - channel base sandstone facies (good porosity, moderate permeability),
(ii) facies B - channel fill sandstone facies (very good porosity, moderate permeability),
(iii) facies C - channel top sandstone (moderate porosity, moderate permeability),
(iv) facies D - overbank claystone facies (poor porosity, poor permeability).
Of these, facies A, B and C represent fluvial channel deposits and these contribute to net reservoir; facies D represents floodplain deposits and does not form net reservoir.
4. Study the core photographs in Fig. 5.3, which depict representative examples of facies types A, B, C. Note the proportion of each facies that has been bleached white by the former presence of oil or which is black due to the presence of residual oil, versus the proportion that has remained red because it has never been in contact with any oil. Record these proportions (in percent) next to each core photo. None of facies D shows any evidence of ever having contained oil.
5. The representative core from Well E-1 (Fig 5.4) shows the distribution of the four facies types (A, B, C, D). Calculate the proportion of the core represented by each of these facies and record these values on Fig. 5.4.
6. Use your estimates from questions 4 and 5 above to determine reservoir net:gross based on your observations from this single core.
7. From the thin section photographs in Fig. 5.5., estimate the porosity of facies types A, B and C. Record the porosity (e.g. 0.35 = 35%) next to each facies type. Facies D has a porosity of just 0.2% and doesn't contribute to the net reservoir, so can be ignored.
8. Based on your values for the relative proportions of each of the facies types in the core (made in 5 above), calculate the mean porosity of the reservoir interval:
Given that reservoir engineers have provided you with data relating to hydrocarbon saturation and recovery factor, you now have enough information to calculate the likely recoverable reserves. For the field to be viable there needs to be at least 1.5x106 m3 of recoverable petroleum fluids (either oil or gas).
10. Calculate the in-situ gas volume and the in-situ oil volume within the reservoir using the data provided in Fig 5.6, together with your estimates for net:gross and porosity.
11. Calculate the recoverable volume of gas and the recoverable volume of oil in the reservoir using the data provided in Fig. 5.6.
12. Is the field a viable prospect? Remember, to be viable there needs to be at least 1.5x106 m3 of recoverable petroleum fluids (either oil or gas).
Your boss is worried that the estimates of net:gross and porosity could be prone to error because they are based on data from a single cored interval in this frontier field. He asks you to re-calculate potential recoverable reserves with values for these key parameters that are firstly 20% lower and secondly 20% higher than your original estimates.
13. Calculate the revised estimates and fill in the tables in Fig. 5.6. How does this affect your perception of whether the field is viable? Which set of figures do you believe?
14. Do you advise your company to go ahead and develop the field? If it is a success, promotion and a holiday to Barbados is guaranteed. If it is a failure, then your career could be in doubt! The CEO of Megabucks Oil is on the phone and she wants an answer now!
https://www.dropbox.com/s/6it1o92y8rqihej/Hydrocarbon-Resources-Practical-Workbook.pdf?dl=0