Scope Field Project
Abstract
By using the given structure contour map for the Scope field, the given parameters as well as the assumptions, the Oil and Gas Reserve was calculated and are given below:
Table 1: Gas Reserves estimate Gas Reserves | | | m3 | Bft3 | 1P | 1.30E+10 | 368.1 |
Table 2: Oil Reserves estimate Oil Reserves | | | m3 | MMbbl | 1P | 2.64E+08 | 663.6 | 2P | 3.67E+08 | 922.6 | 3P | 8.44E+08 | 2123.3 |
The properties of the reservoir can be expected to change due to the effect of heterogeneity which is described as in the results section of this report. A platform and certain vertical and horizontal wells were suggested where the vertical wells were suggested to be drilled in the thick oil column which is at the …show more content…
middle region of the structure contour map as it can achieve great vertical reach of the oil whereas horizontal wells were suggested to be drilled near the oil-water contact at the structure contour map as the oil column is not as thick at that region. The optimum production rate calculated from the assumed field life was found to be 126000 bbl/day. The ratio of vertical to horizontal wells drilled was suggested to be 20:6 but can easily be changed and is completely up to the company.
The four wells are suggested to be perforated at the centre of the column as this will reduce if not eradicate the effects of the gas and water coning. Pressure maintenance by water or gas injection may not be needed as the volume of the gas cap is substantial and may be enough to be used as a pressure maintenance mechanism by means of Gas Cap expansion. Due to this and also for the fear of the production of oil being affected by the production of gas, it is suggested that the Gas Cap gas should not be produced along with the oil.
Table of Contents
Abstract 2 Introduction 4 Methodology 6 Estimating oil- and gas-in-place 6 Estimating Oil- and Gas-in-place and Oil/Gas Reserves 9 Results and Discussion 10 Estimated Gas and Oil Reserves (Task 1) 10 Expected reservoir heterogeneity within the reservoir (Task 2) 10 Preferred platform and well locations (Task 3) 11 Preferred perforation intervals in the four wells (Task 4) 14 Whether pressure maintenance by water or gas injection will be needed during development? (Task 5) Whether Gas Cap gas is preferred to be produced along with oil? (Task 6) 14 Conclusion 15 Recommendations 15 References 16 Appendices 17 Appendix 1: Structure contour map for Scope Field 17 Appendix 2: Original Iso-pay maps drawn for 1P gas reserve estimation and 1P, 2P & 3P oil reserve estimation 18 Appendix 3: Original calculations made to calculate final volume 22 Appendix 4: Assignment question paper 25
Introduction
The degree to which the estimation of oil and gas reserves is accurate depends entirely on the availability, quantity and quality of the available data to be used. The estimation of oil and gas reserves is a completely complex process which involves the integration of geological, geophysical, reservoir and production engineering data. In order to arrive at the most likely reserves, the reserves are estimated by using deterministic and probabilistic methods as there are various uncertainties that are involved in the estimating the reserves.
In defining the hydrocarbon, Reserves refers to the quantities of oil and gas which can be commercially recovered from a given date forward whereas Resources are the reserves plus additional oil and gas that cannot be produced due to techno-economic factors.
In the different stages of a field exploration and developments there are different reserves estimate methods that are generally used at the respective stages. One of the methods which is generally used from when the field is discovered up to when it is abandoned is the Oil and Gas-In-Place method at surface conditions. As usually only some of the oil and gas-in—place can be recovered, therefore the total oil and gas-in-place must be multiplied by a certain recovery factor which depends on the individual field. Moreover, when oil and gas are brought to the surface it shrinks and expands respectively. Therefore if the surface volume of the in-place oil and gas were to be calculated, the Formation Volume Factor which accounts for the shrinkage and expansion factors, should be divided and multiplied respectively for the oil and gas.
From there the formula to estimate the oil and gas reserves are given as:
Oil Reserves = A×hP×∅×SO×NGFVF×RF
Gas Reserves = A×hP×∅×Sg×NG×FVF×RF
Where A = Oil/Gas pool area hP = Oil/Gas pay thickness φ = Porosity So / Sg = Oil/Gas saturation N/G = Net to Gross Ratio FVF = Formation Volume Factor for Oil/Gas RF = Recovery Factor for Oil/Gas
Apart from the formula, Structure Contour Maps are also utilized to help in calculating the oil and gas reserves.
The main objective of this project is to estimate volumetrically the oil and gas in place for the Scope field as well as giving initial preliminary broad field development strategy for the Scope field.
The scope field is an offshore field which has gas cap and bottom water. The field is located at a distance of 70 km from the nearest port and is at a water depth of 80 m. So far, four sub-sea completions have been drilled in the region. The scope field has a north-south trending faulted anticlinal structure which is located over a prominent horst block. The hydrocarbon accumulation consists of 15m gas cap, 80m oil column with an infinite aquifer. Furthermore, the hydrocarbon accumulation is within 200m thick blanket sand which had been deposited mainly as Barrier Bars which were occasionally cut by distributary Channels.
The tasks for this project are: 1. Estimate oil-in-place volumes in the 1P (Proven), 2P (Proven + Probable) and 3P (Proven + Probable + Possible) categories based on the SPE/WPC 1997 guidelines and to estimate gas-in-place volumes in 1P (Proven) category. 2. To describe briefly the expected reservoir heterogeneity within the reservoir 3. Indicate preferred platform location to achieve optimum oil production, along with well locations 4. Indicate preferred perforation intervals in four wells 5. Whether pressure maintenance by water or gas injection will be needed during development 6. Whether Gas Cap gas is preferred to be produced along with oil.
Methodology
Estimating oil- and gas-in-place
Estimating the rock volumes
A structure contour map for the Scope Field has been given and can be referred to in Appendix 1. By using this structure contour map, Iso-Pay maps were then constructed. The Iso-Pay maps were drawn in accordance to each of the categories (1P, 2P or 3P). The Iso-pay maps drawn could be referred to in Appendix 2.
For the 1P Gas Reserve Iso-Pay, the Iso-Pay value at the Gas-Oil Contact (GOC) is zero and it gradually increases to 15m at the crest depending on the structural gain (For example, a structure increase of 10m increases the Iso-Pay by 10m). For the 1P Oil Reserve Iso-Pay, the Iso-pay value within the entire gas cap is 60m and reduces to zero at 1280 mSS depending on the structural fall. At 1280 mSS is the lowest tested oil. 1P category is where there is 90% confidence. For 2P Oil Reserve Iso-Pay, the Iso-pay value within the entire gas cap is 80m and falls to zero at 1300 mSS which is at the Oil-Water Contact (OWC) depending on the structural fall. And the 3P Oil Reserve has an Iso-pay value of 160m in the entire gas cap area and reduces to zero at 1380 mSS which is at the last closed contour depending also on the structural fall. The 2P and 3P categories have 50% and 10% confidence associated with them respectively.
After the Iso-pay contours are constructed, the area between two respective iso-pay contours is estimated by means of drawing the contours on a tracing paper and by inspecting the area by means of an underlying graph paper in units of centimeter square (cm2). Once the area between the two iso-pay contours has been estimated and converted into kilometer-square (km2) according to the given scale, the rock volume is estimated by multiplying the area converted to meter-square (m2) by the average thickness in meters (m) between the two Iso-Pay contour values.
The above is done for all the 1P Gas Reserve Iso-pay and the 1P, 2P and 3P Oil Reserve Iso-pays. An example of the above is as follows. The diagram above shows the 1P iso-pay contour map of the Gas Cap.
Figure 1: 1P gas Iso-pay contour map
As explained before the iso-pay value ranges from zero to fifteen which depends on the structural gain which was from (1220 to 1205 mSS). The three areas are divided into Area A, B and C respectively. Therefore in order to find the rock volume between the 15 and 10 iso-pay values (Area B), the area between them is first calculated. This is shown below:
Figure 2: Estimating area between iso-pay contours
One small box between the iso-pay contours represents the 1 centimeter-square (1 cm2) box of the graph paper. Therefore if there are two of the small boxes it means that the area is 2 centimeter-square (2 cm2). For Area B it has been estimated that the area is around 15.5 cm2. The average thickness between the two contours is (10+15)/2 m which gives a value of 12.5 m. The rock volume is then calculated by multiplying the estimated area converted to kilometer-square (km2) according to the scale and then to meter-square (m2) by the average thickness.
The above is then repeated for the other contours and other iso-pay maps as well.
Estimating Oil- and Gas-in-place and Oil/Gas Reserves
Once the rock volume is calculated, the Oil- and Gas- in place are calculated by using the rock volume and other parameters and are given by:
Oil-in-Place = A×hP×∅×SO×NGFVF
Gas-in-Place = A×hP×∅×Sg×NG×FVF
As explained before, Reserves are the hydrocarbon that can commercially be recovered. Only a percentage of the Oil- and Gas-in-Place can be recovered and this is given by the Recovery Factor (RF). Therefore, the Oil and Gas Reserves are then given by:
Oil Reserves = A×hP×∅×SO×NGFVF×RF
Gas Reserves = A×hP×∅×Sg×NG×FVF×RF
Where the parameters have been explained in the previous section of the report.
Results and Discussion
Estimated Gas and Oil Reserves (Task 1)
Assumptions made in estimating Gas and Oil Reserves are: * Techno-economic/technical recovery factor for oil is 40% * Techno-economic/technical recovery factor for gas is 80%
The tables below shows the estimated Gas and Oil Reserves in cubic-meter (m3) which was then converted to Billion-cubic-feet (Bft3) and Million-Barrels (MMbbl) respectively. For the full set of tables and scale, refer to Appendix 3.
Table 1: Gas Reserves estimate Gas Reserves | | | m3 | Bft3 | 1P | 1.30E+10 | 368.1 |
Table 2: Oil Reserves estimate Oil Reserves | | | m3 | MMbbl | 1P | 2.64E+08 | 663.6 | 2P | 3.67E+08 | 922.6 | 3P | 8.44E+08 | 2123.3 |
Expected reservoir heterogeneity within the reservoir (Task 2)
Heterogeneity within barrier bar affecting fluid flow through the reservoir:
* Increase in the porosity and permeability vales and decrease in the shaliness from bottom to top. * Long continuous marine shale layers located towards lower section of the reservoir may compartmentalise the reservoir. * No flow boundary between underlying basement rock and overlain bar sediments. * Presence of high angle sedimentary structures to cause non linear flow through the reservoir. * No flow boundary between bar sediments and scouring distributary channels.
Heterogeneity within distributary channels affecting fluid flow through the reservoir: * Decrease in porosity, permeability from channel bottom to top. * Increasing number of thin short interlayer stochastic shale bands towards the top section of the channel. * Reservoir Heterogeneity is also caused by dispersed coals, clay balls, clay stones, pyrite within the reservoir. * Burrows by micro organisms piercing through shale/claystone layers open windows for the fluid flow. * Bioturbation generates clays within reservoir.
Preferred platform and well locations (Task 3)
In the development of the field, the location and number of wells is certainly important for the optimum exploitation or production of the oil in the field. Furthermore, the location of the platform should be strategic so that it may benefit the company. Below shows my suggested locations of the platform and wells.
Figure 3: Locations of platform and wells
The assumptions made are as follows: * Average oil production of 4,000bbls/day for vertical wells. * Average oil production of 10,000bbls/day for 500 m long horizontal wells * Field life is 20 years
The main reason that the vertical wells are placed mostly at the centre of the structure map is because at those regions the oil column would be thicker. Therefore, vertical wells are best to be used in these regions as these wells can cover more vertically and thus recover more of the oil. Horizontal wells are placed nearer to the OWC at the structure map as if it is drilled in this region, the oil column would not be as thick and horizontal wells would be more suitable here. This is because the horizontal wells would cover more area horizontally and most importantly could produce more oil without encouraging as much water encroachment as vertical wells will do. As the drainage area of the horizontal wells is bigger, the pressure differential caused by the production would be lower therefore the water column would rise slowly than it would in a vertical well.
The strategic placement of the platform could be in the middle where it is at the centre of most of the wells. This is so that all the wells could be produced to the platform only so that the transportation of the produced oil would be easier as the transport vessel would only have to move between the port and the platform only. This will ensure that the company could save in operating expenses.
In terms of the number of wells, the ratio between the numbers of vertical to horizontal wells could be varied depending on the different reasons. In accordance to the above assumption on the field life which is 20 years and the estimated 2P volume which is 922.6 MMbbl, the optimum number of barrels per day produced can be calculated.
Optimum number of barrels per day = 2P Volume of oilField life = 922.6×106bbl20×365 days ≈ 126000 bbl/day
A possible ratio of vertical to horizontal wells that could be drilled to achieve the above rate of production is 20:6. This means that 20 vertical wells and 6 horizontal wells could be drilled. This ratio could be varied depending on the company itself after weighing the gains or losses. A possible advantage of the vertical wells is that as mentioned before at thick oil columns, these wells could cover more area vertically and would produce more oil as a result. A possible disadvantage is that a lot of these vertical wells may need to be drilled. Whereas for horizontal wells, the possible advantage is that the rate of production would be faster and less number of wells could be drilled which would lead to a decrease in operating expenses. A possible disadvantage would be that it would not be able to cover more vertically as can a vertical well. These are only some of the factors that are considered, there are certainly many other factors that should be considered and this should be done by the company itself and used as a method to determine the optimum number of wells that should be drilled.
Preferred perforation intervals in the four wells (Task 4)
Gas coning and water coning are a serious issue that should be discussed thoroughly by the engineers so that the perforation intervals could be well-planned so as to prevent or reduce the gas and water coning. This is because if gas and water coning occurs, it will greatly reduce the production of oil and ultimately will greatly reduce the income gained for the company.
For this field, the initial perforations could be done at the centre of the column where it is at the centre between the gas cap and the oil-water contact (OWC). This will ensure that the effect of the gas and water coning would be greatly reduced, if not eradicated.
Whether pressure maintenance by water or gas injection will be needed during development? (Task 5) Whether Gas Cap gas is preferred to be produced along with oil? (Task 6)
As it can be seen from the calculated 1P gas volume estimation, the volume of gas estimated is 368 Bft3. The gas cap is clearly large which could give a good pressure maintenance mechanism which is by Gas Cap expansion. As the oil is produced, the volume left by the produced oil would be occupied by the Gas Cap which results in the expansion of the Gas Cap. As the volume of the Gas Cap is considerably large, therefore pressure maintenance by water or gas injection may not be needed during the development of the field.
The Gas Cap should not be preferred to be produced along with the oil. This is because as mentioned above, the gas cap provides a good pressure maintenance mechanism, so if the gas cap is produced the effect of the Gas Cap Expansion may not be as great as before. Furthermore, the production of the gas may override the production of oil as gas is lighter than the oil. This will have an adverse effect on the economics as oil is commercially ready and has a large market as opposed to gas.
Conclusion
In conclusion it can be seen that the volume of Oil and Gas reserves is good with the 1P estimation of Gas Reserve giving a value of 368.1 Bft3 and the 1P, 2P and 3P estimations of Oil Reserves giving values of 663, 922 and 2123 MMbbl. The heterogeneity expected in the reservoir does have a profound effect on the properties of the reservoir as a whole. Also, in the previous section the preferred location of the platform and the wells had been presented with the reasons included. Furthermore, the number of vertical wells to horizontal wells that could be drilled depends entirely on the company. In the initial perforation of the four wells, it could be perforated in the center so that effect of the gas and water coning could be reduced if it is not prevented. The Gas Cap gas should not be preferred to be produced with the oil as it will reduce the production of oil and reduce the effect of the Gas Cap expansion as a mechanism for pressure maintenance. The Gas Cap expansion could be used as a great pressure maintenance mechanism therefore water or gas injection may not be needed.
As explained before, all of these factors depend entirely on the company itself. This is because the company should weigh the different factors that are involved for the well-being of the company as a whole.
Recommendations
In the structure contour map given for the assignment, there are no indications of the North or South directions. This may be important to understand how the structure looks like and to explain regarding the direction of the horizontal wells that may be drilled. Furthermore, a better understanding of the drainage areas of the vertical and horizontal wells may help in determining the locations and the optimum number of wells that may be drilled to achieve optimum recovery. Last but not least, the heterogeneity of the reservoir may be understood more so that the well locations may be suggested more accurately as needed.
References
PTRL 3003/5006 Field Development Geology course notes, 2010, School of Petroleum Engineering, University of New South Wales, Sydney
PTRL 3003/5006 Field Development Geology Assignment question paper, 2010, School of Petroleum Engineering, University of New South Wales, Sydney
Appendices
Appendix 1: Structure contour map for Scope Field
Appendix 2: Original Iso-pay maps drawn for 1P gas reserve estimation and 1P, 2P & 3P oil reserve estimation
Appendix 3: Original calculations made to calculate final volume
Scale | | | | | | | | cm | km | | km | m | | m^3 | bbl | ft^3 | 2.7 | 2.0 | | 1 | 1000 | | 1 | 6.29 | 35.31 | 1 | 0.740740741 | | km^2 | m^2 | | | | cm^2 | km^2 | | 1 | 1000000 | | | | 1 | 0.548696845 | | | | | | |
Given Parameters | | | | | Gas Cap (GOC at 1220mSS) | | | | Well | Pay top mSS | Avg. Porosity % | Gas Sasturation Sg % | Net/Gross ratio | FVF V/V | Scope #1 | 1205 | 0.38 | 0.9 | 0.95 | 260 | Scope #2 | 1208 | 0.36 | 0.85 | 0.9 | 260 | Average | 1206.5 | 0.37 | 0.875 | 0.925 | 260 | | | | | | | Oil Column (OWC at 1300 mSS) | | | | Well | Pay top mSS | Avg. Porosity % | Oil Sasturation So % | Net/Gross ratio | FVF V/V | Scope #1 | 1220 | 0.36 | 0.75 | 0.85 | 1.3 | Scope #2 | 1208 | 0.34 | 0.7 | 0.8 | 1.3 | Scope #3 | 1278 | 0.3 | 0.6 | 0.7 | 1.3 | Scope #4 | 1248 | 0.32 | 0.65 | 0.75 | 1.3 | Average | 1238.5 | 0.33 | 0.675 | 0.775 | 1.3 | | | | | | | Estimated Parameters | | | | | Gas Reserve Rock Volume 1P | | | | | Thickness (m) | Area (cm^2) | Area (km^2) | Area (m^2) | Volume (m^3) | A | 15 | 3.5 | 1.92 | 1920439 | 28806584 | B | 12.5 | 15.5 | 8.50 | 8504801 | 106310014 | C | 5 | 11.75 | 6.45 | 6447188 | 32235940 | Total | | 30.75 | | | 1.67E+08 | | | | | | |
Oil Reserve Rock Volume 1P | | | | | Thickness (m) | Area (cm^2) | Area (km^2) | Area (m^2) | Volume (m^3) | A | 60 | 30.75 | 16.87 | 16872428 | 1012345679 | B | 55 | 16 | 8.78 | 8779150 | 482853224 | C | 45 | 13 | 7.13 | 7133059 | 320987654 | D | 35 | 6.5 | 3.57 | 3566529 | 124828532 | E | 15 | 5.5 | 3.02 | 3017833 | 45267490 | Total | | 71.75 | | | 1.99E+09 | | | | | | | Oil Reserve Rock Volume 2P | | | | | Thickness (m) | Area (cm^2) | Area (km^2) | Area (m^2) | Volume (m^3) | A | 80 | 30.75 | 16.87 | 16872428 | 1349794239 | B | 75 | 16 | 8.78 | 8779150 | 658436214 | C | 65 | 13 | 7.13 | 7133059 | 463648834 | D | 50 | 6.5 | 3.57 | 3566529 | 178326475 | E | 30 | 5.5 | 3.02 | 3017833 | 90534979 | F | 10 | 3.75 | 2.06 | 2057613 | 20576132 | Total | | 75.5 | | | 2.76E+09 | | | | | | | Oil Reserve Rock Volume 3P | | | | | Thickness (m) | Area (cm^2) | Area (km^2) | Area (m^2) | Volume (m^3) | A | 160 | 30.75 | 16.87 | 16872428 | 2699588477 | B | 155 | 16 | 8.78 | 8779150 | 1360768176 | C | 145 | 13 | 7.13 | 7133059 | 1034293553 | D | 130 | 6.5 | 3.57 | 3566529 | 463648834 | E | 110 | 5.5 | 3.02 | 3017833 | 331961591 | F | 90 | 3.75 | 2.06 | 2057613 | 185185185
| G | 70 | 3.5 | 1.92 | 1920439 | 134430727 | H | 50 | 3 | 1.65 | 1646091 | 82304527 | I | 30 | 3 | 1.65 | 1646091 | 49382716 | J | 10 | 2.5 | 1.37 | 1371742 | 13717421 | Total | | 87.5 | | | 6.36E+09 |
Calculated Parameters | | | | | | | | Gas Cap | | | | | | | | | | | Avg. Porosity % | Gas Sasturation Sg % | Net/Gross ratio | FVF V/V | RF % | Rock Volume (m^3) | Gas-in-place (m^3) | Gas-in-place (ft^3) | Gas Reserve (Bft^3) | 1P | 0.37 | 0.875 | 0.925 | 260 | 0.80 | 167352538 | 1.30E+10 | 4.60E+11 | 368.1 | | | | | | | | | | | Oil Column | | | | | | | | | | Avg. Porosity % | Gas Sasturation Sg % | Net/Gross ratio | FVF V/V | RF % | Rock Volume (m^3) | Oil-in-place (m^3) | Oil-in-place (MMbbl) | Oil Reserve (MMbbl) | 1P | 0.33 | 0.675 | 0.775 | 1.3 | 0.40 | 1.986E+09 | 2.64E+08 | 1.66E+03 | 663.6 | 2P | 0.33 | 0.675 | 0.775 | 1.3 | 0.40 | 2.761E+09 | 3.67E+08 | 2.31E+03 | 922.6 | 3P | 0.33 | 0.675 | 0.775 | 1.3 | 0.40 | 6.355E+09 | 8.44E+08 | 5.31E+03 | 2123.3 |
Appendix 4: Assignment question paper
By using the given structure contour map for the Scope field, the given parameters as well as the assumptions, the Oil and Gas Reserve was calculated and are given below:
Table 1: Gas Reserves estimate Gas Reserves | | | m3 | Bft3 | 1P | 1.30E+10 | 368.1 |
Table 2: Oil Reserves estimate Oil Reserves | | | m3 | MMbbl | 1P | 2.64E+08 | 663.6 | 2P | 3.67E+08 | 922.6 | 3P | 8.44E+08 | 2123.3 |
The properties of the reservoir can be expected to change due to the effect of heterogeneity which is described as in the results section of this report. A platform and certain vertical and horizontal wells were suggested where the vertical wells were suggested to be drilled in the thick oil column which is at the …show more content…
middle region of the structure contour map as it can achieve great vertical reach of the oil whereas horizontal wells were suggested to be drilled near the oil-water contact at the structure contour map as the oil column is not as thick at that region. The optimum production rate calculated from the assumed field life was found to be 126000 bbl/day. The ratio of vertical to horizontal wells drilled was suggested to be 20:6 but can easily be changed and is completely up to the company.
The four wells are suggested to be perforated at the centre of the column as this will reduce if not eradicate the effects of the gas and water coning. Pressure maintenance by water or gas injection may not be needed as the volume of the gas cap is substantial and may be enough to be used as a pressure maintenance mechanism by means of Gas Cap expansion. Due to this and also for the fear of the production of oil being affected by the production of gas, it is suggested that the Gas Cap gas should not be produced along with the oil.
Table of Contents
Abstract 2 Introduction 4 Methodology 6 Estimating oil- and gas-in-place 6 Estimating Oil- and Gas-in-place and Oil/Gas Reserves 9 Results and Discussion 10 Estimated Gas and Oil Reserves (Task 1) 10 Expected reservoir heterogeneity within the reservoir (Task 2) 10 Preferred platform and well locations (Task 3) 11 Preferred perforation intervals in the four wells (Task 4) 14 Whether pressure maintenance by water or gas injection will be needed during development? (Task 5) Whether Gas Cap gas is preferred to be produced along with oil? (Task 6) 14 Conclusion 15 Recommendations 15 References 16 Appendices 17 Appendix 1: Structure contour map for Scope Field 17 Appendix 2: Original Iso-pay maps drawn for 1P gas reserve estimation and 1P, 2P & 3P oil reserve estimation 18 Appendix 3: Original calculations made to calculate final volume 22 Appendix 4: Assignment question paper 25
Introduction
The degree to which the estimation of oil and gas reserves is accurate depends entirely on the availability, quantity and quality of the available data to be used. The estimation of oil and gas reserves is a completely complex process which involves the integration of geological, geophysical, reservoir and production engineering data. In order to arrive at the most likely reserves, the reserves are estimated by using deterministic and probabilistic methods as there are various uncertainties that are involved in the estimating the reserves.
In defining the hydrocarbon, Reserves refers to the quantities of oil and gas which can be commercially recovered from a given date forward whereas Resources are the reserves plus additional oil and gas that cannot be produced due to techno-economic factors.
In the different stages of a field exploration and developments there are different reserves estimate methods that are generally used at the respective stages. One of the methods which is generally used from when the field is discovered up to when it is abandoned is the Oil and Gas-In-Place method at surface conditions. As usually only some of the oil and gas-in—place can be recovered, therefore the total oil and gas-in-place must be multiplied by a certain recovery factor which depends on the individual field. Moreover, when oil and gas are brought to the surface it shrinks and expands respectively. Therefore if the surface volume of the in-place oil and gas were to be calculated, the Formation Volume Factor which accounts for the shrinkage and expansion factors, should be divided and multiplied respectively for the oil and gas.
From there the formula to estimate the oil and gas reserves are given as:
Oil Reserves = A×hP×∅×SO×NGFVF×RF
Gas Reserves = A×hP×∅×Sg×NG×FVF×RF
Where A = Oil/Gas pool area hP = Oil/Gas pay thickness φ = Porosity So / Sg = Oil/Gas saturation N/G = Net to Gross Ratio FVF = Formation Volume Factor for Oil/Gas RF = Recovery Factor for Oil/Gas
Apart from the formula, Structure Contour Maps are also utilized to help in calculating the oil and gas reserves.
The main objective of this project is to estimate volumetrically the oil and gas in place for the Scope field as well as giving initial preliminary broad field development strategy for the Scope field.
The scope field is an offshore field which has gas cap and bottom water. The field is located at a distance of 70 km from the nearest port and is at a water depth of 80 m. So far, four sub-sea completions have been drilled in the region. The scope field has a north-south trending faulted anticlinal structure which is located over a prominent horst block. The hydrocarbon accumulation consists of 15m gas cap, 80m oil column with an infinite aquifer. Furthermore, the hydrocarbon accumulation is within 200m thick blanket sand which had been deposited mainly as Barrier Bars which were occasionally cut by distributary Channels.
The tasks for this project are: 1. Estimate oil-in-place volumes in the 1P (Proven), 2P (Proven + Probable) and 3P (Proven + Probable + Possible) categories based on the SPE/WPC 1997 guidelines and to estimate gas-in-place volumes in 1P (Proven) category. 2. To describe briefly the expected reservoir heterogeneity within the reservoir 3. Indicate preferred platform location to achieve optimum oil production, along with well locations 4. Indicate preferred perforation intervals in four wells 5. Whether pressure maintenance by water or gas injection will be needed during development 6. Whether Gas Cap gas is preferred to be produced along with oil.
Methodology
Estimating oil- and gas-in-place
Estimating the rock volumes
A structure contour map for the Scope Field has been given and can be referred to in Appendix 1. By using this structure contour map, Iso-Pay maps were then constructed. The Iso-Pay maps were drawn in accordance to each of the categories (1P, 2P or 3P). The Iso-pay maps drawn could be referred to in Appendix 2.
For the 1P Gas Reserve Iso-Pay, the Iso-Pay value at the Gas-Oil Contact (GOC) is zero and it gradually increases to 15m at the crest depending on the structural gain (For example, a structure increase of 10m increases the Iso-Pay by 10m). For the 1P Oil Reserve Iso-Pay, the Iso-pay value within the entire gas cap is 60m and reduces to zero at 1280 mSS depending on the structural fall. At 1280 mSS is the lowest tested oil. 1P category is where there is 90% confidence. For 2P Oil Reserve Iso-Pay, the Iso-pay value within the entire gas cap is 80m and falls to zero at 1300 mSS which is at the Oil-Water Contact (OWC) depending on the structural fall. And the 3P Oil Reserve has an Iso-pay value of 160m in the entire gas cap area and reduces to zero at 1380 mSS which is at the last closed contour depending also on the structural fall. The 2P and 3P categories have 50% and 10% confidence associated with them respectively.
After the Iso-pay contours are constructed, the area between two respective iso-pay contours is estimated by means of drawing the contours on a tracing paper and by inspecting the area by means of an underlying graph paper in units of centimeter square (cm2). Once the area between the two iso-pay contours has been estimated and converted into kilometer-square (km2) according to the given scale, the rock volume is estimated by multiplying the area converted to meter-square (m2) by the average thickness in meters (m) between the two Iso-Pay contour values.
The above is done for all the 1P Gas Reserve Iso-pay and the 1P, 2P and 3P Oil Reserve Iso-pays. An example of the above is as follows. The diagram above shows the 1P iso-pay contour map of the Gas Cap.
Figure 1: 1P gas Iso-pay contour map
As explained before the iso-pay value ranges from zero to fifteen which depends on the structural gain which was from (1220 to 1205 mSS). The three areas are divided into Area A, B and C respectively. Therefore in order to find the rock volume between the 15 and 10 iso-pay values (Area B), the area between them is first calculated. This is shown below:
Figure 2: Estimating area between iso-pay contours
One small box between the iso-pay contours represents the 1 centimeter-square (1 cm2) box of the graph paper. Therefore if there are two of the small boxes it means that the area is 2 centimeter-square (2 cm2). For Area B it has been estimated that the area is around 15.5 cm2. The average thickness between the two contours is (10+15)/2 m which gives a value of 12.5 m. The rock volume is then calculated by multiplying the estimated area converted to kilometer-square (km2) according to the scale and then to meter-square (m2) by the average thickness.
The above is then repeated for the other contours and other iso-pay maps as well.
Estimating Oil- and Gas-in-place and Oil/Gas Reserves
Once the rock volume is calculated, the Oil- and Gas- in place are calculated by using the rock volume and other parameters and are given by:
Oil-in-Place = A×hP×∅×SO×NGFVF
Gas-in-Place = A×hP×∅×Sg×NG×FVF
As explained before, Reserves are the hydrocarbon that can commercially be recovered. Only a percentage of the Oil- and Gas-in-Place can be recovered and this is given by the Recovery Factor (RF). Therefore, the Oil and Gas Reserves are then given by:
Oil Reserves = A×hP×∅×SO×NGFVF×RF
Gas Reserves = A×hP×∅×Sg×NG×FVF×RF
Where the parameters have been explained in the previous section of the report.
Results and Discussion
Estimated Gas and Oil Reserves (Task 1)
Assumptions made in estimating Gas and Oil Reserves are: * Techno-economic/technical recovery factor for oil is 40% * Techno-economic/technical recovery factor for gas is 80%
The tables below shows the estimated Gas and Oil Reserves in cubic-meter (m3) which was then converted to Billion-cubic-feet (Bft3) and Million-Barrels (MMbbl) respectively. For the full set of tables and scale, refer to Appendix 3.
Table 1: Gas Reserves estimate Gas Reserves | | | m3 | Bft3 | 1P | 1.30E+10 | 368.1 |
Table 2: Oil Reserves estimate Oil Reserves | | | m3 | MMbbl | 1P | 2.64E+08 | 663.6 | 2P | 3.67E+08 | 922.6 | 3P | 8.44E+08 | 2123.3 |
Expected reservoir heterogeneity within the reservoir (Task 2)
Heterogeneity within barrier bar affecting fluid flow through the reservoir:
* Increase in the porosity and permeability vales and decrease in the shaliness from bottom to top. * Long continuous marine shale layers located towards lower section of the reservoir may compartmentalise the reservoir. * No flow boundary between underlying basement rock and overlain bar sediments. * Presence of high angle sedimentary structures to cause non linear flow through the reservoir. * No flow boundary between bar sediments and scouring distributary channels.
Heterogeneity within distributary channels affecting fluid flow through the reservoir: * Decrease in porosity, permeability from channel bottom to top. * Increasing number of thin short interlayer stochastic shale bands towards the top section of the channel. * Reservoir Heterogeneity is also caused by dispersed coals, clay balls, clay stones, pyrite within the reservoir. * Burrows by micro organisms piercing through shale/claystone layers open windows for the fluid flow. * Bioturbation generates clays within reservoir.
Preferred platform and well locations (Task 3)
In the development of the field, the location and number of wells is certainly important for the optimum exploitation or production of the oil in the field. Furthermore, the location of the platform should be strategic so that it may benefit the company. Below shows my suggested locations of the platform and wells.
Figure 3: Locations of platform and wells
The assumptions made are as follows: * Average oil production of 4,000bbls/day for vertical wells. * Average oil production of 10,000bbls/day for 500 m long horizontal wells * Field life is 20 years
The main reason that the vertical wells are placed mostly at the centre of the structure map is because at those regions the oil column would be thicker. Therefore, vertical wells are best to be used in these regions as these wells can cover more vertically and thus recover more of the oil. Horizontal wells are placed nearer to the OWC at the structure map as if it is drilled in this region, the oil column would not be as thick and horizontal wells would be more suitable here. This is because the horizontal wells would cover more area horizontally and most importantly could produce more oil without encouraging as much water encroachment as vertical wells will do. As the drainage area of the horizontal wells is bigger, the pressure differential caused by the production would be lower therefore the water column would rise slowly than it would in a vertical well.
The strategic placement of the platform could be in the middle where it is at the centre of most of the wells. This is so that all the wells could be produced to the platform only so that the transportation of the produced oil would be easier as the transport vessel would only have to move between the port and the platform only. This will ensure that the company could save in operating expenses.
In terms of the number of wells, the ratio between the numbers of vertical to horizontal wells could be varied depending on the different reasons. In accordance to the above assumption on the field life which is 20 years and the estimated 2P volume which is 922.6 MMbbl, the optimum number of barrels per day produced can be calculated.
Optimum number of barrels per day = 2P Volume of oilField life = 922.6×106bbl20×365 days ≈ 126000 bbl/day
A possible ratio of vertical to horizontal wells that could be drilled to achieve the above rate of production is 20:6. This means that 20 vertical wells and 6 horizontal wells could be drilled. This ratio could be varied depending on the company itself after weighing the gains or losses. A possible advantage of the vertical wells is that as mentioned before at thick oil columns, these wells could cover more area vertically and would produce more oil as a result. A possible disadvantage is that a lot of these vertical wells may need to be drilled. Whereas for horizontal wells, the possible advantage is that the rate of production would be faster and less number of wells could be drilled which would lead to a decrease in operating expenses. A possible disadvantage would be that it would not be able to cover more vertically as can a vertical well. These are only some of the factors that are considered, there are certainly many other factors that should be considered and this should be done by the company itself and used as a method to determine the optimum number of wells that should be drilled.
Preferred perforation intervals in the four wells (Task 4)
Gas coning and water coning are a serious issue that should be discussed thoroughly by the engineers so that the perforation intervals could be well-planned so as to prevent or reduce the gas and water coning. This is because if gas and water coning occurs, it will greatly reduce the production of oil and ultimately will greatly reduce the income gained for the company.
For this field, the initial perforations could be done at the centre of the column where it is at the centre between the gas cap and the oil-water contact (OWC). This will ensure that the effect of the gas and water coning would be greatly reduced, if not eradicated.
Whether pressure maintenance by water or gas injection will be needed during development? (Task 5) Whether Gas Cap gas is preferred to be produced along with oil? (Task 6)
As it can be seen from the calculated 1P gas volume estimation, the volume of gas estimated is 368 Bft3. The gas cap is clearly large which could give a good pressure maintenance mechanism which is by Gas Cap expansion. As the oil is produced, the volume left by the produced oil would be occupied by the Gas Cap which results in the expansion of the Gas Cap. As the volume of the Gas Cap is considerably large, therefore pressure maintenance by water or gas injection may not be needed during the development of the field.
The Gas Cap should not be preferred to be produced along with the oil. This is because as mentioned above, the gas cap provides a good pressure maintenance mechanism, so if the gas cap is produced the effect of the Gas Cap Expansion may not be as great as before. Furthermore, the production of the gas may override the production of oil as gas is lighter than the oil. This will have an adverse effect on the economics as oil is commercially ready and has a large market as opposed to gas.
Conclusion
In conclusion it can be seen that the volume of Oil and Gas reserves is good with the 1P estimation of Gas Reserve giving a value of 368.1 Bft3 and the 1P, 2P and 3P estimations of Oil Reserves giving values of 663, 922 and 2123 MMbbl. The heterogeneity expected in the reservoir does have a profound effect on the properties of the reservoir as a whole. Also, in the previous section the preferred location of the platform and the wells had been presented with the reasons included. Furthermore, the number of vertical wells to horizontal wells that could be drilled depends entirely on the company. In the initial perforation of the four wells, it could be perforated in the center so that effect of the gas and water coning could be reduced if it is not prevented. The Gas Cap gas should not be preferred to be produced with the oil as it will reduce the production of oil and reduce the effect of the Gas Cap expansion as a mechanism for pressure maintenance. The Gas Cap expansion could be used as a great pressure maintenance mechanism therefore water or gas injection may not be needed.
As explained before, all of these factors depend entirely on the company itself. This is because the company should weigh the different factors that are involved for the well-being of the company as a whole.
Recommendations
In the structure contour map given for the assignment, there are no indications of the North or South directions. This may be important to understand how the structure looks like and to explain regarding the direction of the horizontal wells that may be drilled. Furthermore, a better understanding of the drainage areas of the vertical and horizontal wells may help in determining the locations and the optimum number of wells that may be drilled to achieve optimum recovery. Last but not least, the heterogeneity of the reservoir may be understood more so that the well locations may be suggested more accurately as needed.
References
PTRL 3003/5006 Field Development Geology course notes, 2010, School of Petroleum Engineering, University of New South Wales, Sydney
PTRL 3003/5006 Field Development Geology Assignment question paper, 2010, School of Petroleum Engineering, University of New South Wales, Sydney
Appendices
Appendix 1: Structure contour map for Scope Field
Appendix 2: Original Iso-pay maps drawn for 1P gas reserve estimation and 1P, 2P & 3P oil reserve estimation
Appendix 3: Original calculations made to calculate final volume
Scale | | | | | | | | cm | km | | km | m | | m^3 | bbl | ft^3 | 2.7 | 2.0 | | 1 | 1000 | | 1 | 6.29 | 35.31 | 1 | 0.740740741 | | km^2 | m^2 | | | | cm^2 | km^2 | | 1 | 1000000 | | | | 1 | 0.548696845 | | | | | | |
Given Parameters | | | | | Gas Cap (GOC at 1220mSS) | | | | Well | Pay top mSS | Avg. Porosity % | Gas Sasturation Sg % | Net/Gross ratio | FVF V/V | Scope #1 | 1205 | 0.38 | 0.9 | 0.95 | 260 | Scope #2 | 1208 | 0.36 | 0.85 | 0.9 | 260 | Average | 1206.5 | 0.37 | 0.875 | 0.925 | 260 | | | | | | | Oil Column (OWC at 1300 mSS) | | | | Well | Pay top mSS | Avg. Porosity % | Oil Sasturation So % | Net/Gross ratio | FVF V/V | Scope #1 | 1220 | 0.36 | 0.75 | 0.85 | 1.3 | Scope #2 | 1208 | 0.34 | 0.7 | 0.8 | 1.3 | Scope #3 | 1278 | 0.3 | 0.6 | 0.7 | 1.3 | Scope #4 | 1248 | 0.32 | 0.65 | 0.75 | 1.3 | Average | 1238.5 | 0.33 | 0.675 | 0.775 | 1.3 | | | | | | | Estimated Parameters | | | | | Gas Reserve Rock Volume 1P | | | | | Thickness (m) | Area (cm^2) | Area (km^2) | Area (m^2) | Volume (m^3) | A | 15 | 3.5 | 1.92 | 1920439 | 28806584 | B | 12.5 | 15.5 | 8.50 | 8504801 | 106310014 | C | 5 | 11.75 | 6.45 | 6447188 | 32235940 | Total | | 30.75 | | | 1.67E+08 | | | | | | |
Oil Reserve Rock Volume 1P | | | | | Thickness (m) | Area (cm^2) | Area (km^2) | Area (m^2) | Volume (m^3) | A | 60 | 30.75 | 16.87 | 16872428 | 1012345679 | B | 55 | 16 | 8.78 | 8779150 | 482853224 | C | 45 | 13 | 7.13 | 7133059 | 320987654 | D | 35 | 6.5 | 3.57 | 3566529 | 124828532 | E | 15 | 5.5 | 3.02 | 3017833 | 45267490 | Total | | 71.75 | | | 1.99E+09 | | | | | | | Oil Reserve Rock Volume 2P | | | | | Thickness (m) | Area (cm^2) | Area (km^2) | Area (m^2) | Volume (m^3) | A | 80 | 30.75 | 16.87 | 16872428 | 1349794239 | B | 75 | 16 | 8.78 | 8779150 | 658436214 | C | 65 | 13 | 7.13 | 7133059 | 463648834 | D | 50 | 6.5 | 3.57 | 3566529 | 178326475 | E | 30 | 5.5 | 3.02 | 3017833 | 90534979 | F | 10 | 3.75 | 2.06 | 2057613 | 20576132 | Total | | 75.5 | | | 2.76E+09 | | | | | | | Oil Reserve Rock Volume 3P | | | | | Thickness (m) | Area (cm^2) | Area (km^2) | Area (m^2) | Volume (m^3) | A | 160 | 30.75 | 16.87 | 16872428 | 2699588477 | B | 155 | 16 | 8.78 | 8779150 | 1360768176 | C | 145 | 13 | 7.13 | 7133059 | 1034293553 | D | 130 | 6.5 | 3.57 | 3566529 | 463648834 | E | 110 | 5.5 | 3.02 | 3017833 | 331961591 | F | 90 | 3.75 | 2.06 | 2057613 | 185185185
| G | 70 | 3.5 | 1.92 | 1920439 | 134430727 | H | 50 | 3 | 1.65 | 1646091 | 82304527 | I | 30 | 3 | 1.65 | 1646091 | 49382716 | J | 10 | 2.5 | 1.37 | 1371742 | 13717421 | Total | | 87.5 | | | 6.36E+09 |
Calculated Parameters | | | | | | | | Gas Cap | | | | | | | | | | | Avg. Porosity % | Gas Sasturation Sg % | Net/Gross ratio | FVF V/V | RF % | Rock Volume (m^3) | Gas-in-place (m^3) | Gas-in-place (ft^3) | Gas Reserve (Bft^3) | 1P | 0.37 | 0.875 | 0.925 | 260 | 0.80 | 167352538 | 1.30E+10 | 4.60E+11 | 368.1 | | | | | | | | | | | Oil Column | | | | | | | | | | Avg. Porosity % | Gas Sasturation Sg % | Net/Gross ratio | FVF V/V | RF % | Rock Volume (m^3) | Oil-in-place (m^3) | Oil-in-place (MMbbl) | Oil Reserve (MMbbl) | 1P | 0.33 | 0.675 | 0.775 | 1.3 | 0.40 | 1.986E+09 | 2.64E+08 | 1.66E+03 | 663.6 | 2P | 0.33 | 0.675 | 0.775 | 1.3 | 0.40 | 2.761E+09 | 3.67E+08 | 2.31E+03 | 922.6 | 3P | 0.33 | 0.675 | 0.775 | 1.3 | 0.40 | 6.355E+09 | 8.44E+08 | 5.31E+03 | 2123.3 |
Appendix 4: Assignment question paper