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TABLE OF CONTENTS

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1. Table of Contents……………………………………………………….2

2. Executive Summary ………………………………………………….....3

3. Introduction……………………………………………………………...4

4. Technical Approach……………………………………………………..5

5. Results…………………………………………………………………...6

6. Discussion……………………………………………………………….7

7. Conclusion……………………………………………………………….8

8. Nomenclature……………………………………………………………11

9. References……………………………………………………………….11

10. Appendix of Figures……………………………………………………..11

11. Appendix of Tables………………………………………………………18

Executive Summary

The Fulmer oil field is located in the southern part of the North Sea off the coast of Norway. The oil reservoir is primarily late Jurassic consolidated sandstone, located at a depth of 3289 meters to 3369 meters with a dip of 1.5 degrees. At this depth the temperature of the reservoir is about 144oC (291.2oF) and the reservoir pressure is approximately 63,000 kPa (9,137psi). The type of hydrocarbons present in this reservoir is oil with a density of 0.77 g/cc. The average thickness is 20m while the net pay thickness is 16m. There are two exploratory wells and they are known as Exp 1 and Exp 2.

The goal of this project is to use the determined OOIP in the Fulmar reservoir and find the best technique to produce from this field using the simulation program CMG. We obtained this data using both initial wells to determine an estimate of the reservoir size, OOIP, and hydrocarbon properties. Exp 1 was primarily designed to be a producing well while the Exp 2 can be used as an injection well. Exp 1 is placed at 3303m while Exp 2 is placed at 3345m. Exp 2 is subjected to be used only as an injection well due to the relative location near to the oil-water contact line.

The top of the Fulmar field at 3289 meters at measured depth mean from sea level (MDMSFL) for Exp 1 and 3353m MDMSFL for Exp 2. After cutoffs were applied to both exploratory wells the results that were given was that Exp 1 had a net pay thickness of 12m with a porosity of 26% and a water saturation of 25%. Exp 2 had a net pay thickness of 19m with a porosity of 21% and a water saturation of 25%. Using the Original oil in place (OOIP) equation: , the calculated OOIP for Exp 1 is 63.82 MMTSB and for Exp 2 it is 81.94 MMSTB.

The parameters found from lab core samples and well logs were used and put into the CMG simulation program. To minimize the cost of drilling, all wells were drilled off the platform and we used the technique of horizontal drilling to give us the highest concentration of surface area to achieve the best recovery factor. To maintain the bottom hole pressure (BHP) we drilled an injection well. The best result achieved was a 44% recovery factor with just two horizontal wells and one injector.

In the upcoming report we will use our OOIP and recovery factor to estimate the net present value (NPV) and compare that to the cost of initiating the well design. This will give us an idea of what the best way will be to develop the Fulmar oil field.

Introduction

This report is an evaluation of an oil field in North Sea off the coast of Norway that was discovered in 1992. The field is known as the Fulmar (Ula) and has a net pay thickness of 16m and a lithology of sandstone. The objective is to find the NPV and find the best solution to produce from this field.

The field lithology is Jurassic Ula sandstone (Fulmar) with the top of the formation at a depth of 3289 meters. The zone is estimated to cover about 5.35Km2 which is 1297.3 acres. Geologic features of the area are mostly Jurassic with fine, well sorted, silica sandstone. The reservoir is located at a depth of 3289-3369m with a dip of 1.5 degrees (Figure 1) and a temperature of 1440C. Two wells were drilled, an exploratory well and an appraisal well. From these two wells core samples were taken.

This project has two different scenarios on how to develop the Fulmar field. One scenario is that we drill strictly off a platform which means the well heads will be dry. The other scenario is that we have subsea well heads. The latter of the scenarios will require possibly a drilling ship and a tie-in structure to another platform to produce. While the first scenario includes the platform already. The choice between the two will come down to cost and what the NPV is.

The NPV is found by using the CMG simulation program with the parameters found in Report 1. This process gives a more accurate resemblance of the reservoir and shows how it will behave during the years of production. There were many simulations ran to find the best recovery factor while also having the least cost to implement it too. The simulation with the highest recovery factor will be used to calculate the NPV using the current oil prices.

The objective of this project is to find the best way to produce the Fulmar field while maintaining a profit after cost have been subtracted from the NPV. The factors used to get an NPV were discussed in the previous report while the cost of how much it will cost to implement the chosen design is discussed in the next report. With all three reports we will be able to analyze the progress of the project and determine if this field is economical.

Technical Approach

The technical approach used in this step of the project was the program CMG. The program does all the calculations and simulates how the reservoir will behave when certain conditions are applied to it. In order to simulate the behavior of the Fulmar field, parameters must be chosen which will dictate the recovery rate, injection capabilities, and water cut. Each parameter was found in either the reports provided to us or found through calculations using the well logging information. The net pay thickness is 16 meters and was divided into four layers in the simulation. The parameters used in the simulations are; permeability is 20 md for I and J, 2 md for K, porosity is 20%, oil saturation is 75%, and water saturation is 25%. These values were used to create a more conservative reservoir simulation. However they are within the recommended parameters given in the lab reports.

The location of the wells for the production and the injection sites is important and the goal is to find an optimal location for both. To achieve an optimal recovery factor and rate the producing wells are strategically placed at the middle of the reservoir and drilled horizontally up to the top of the reservoir on the dip. The injection well is placed at the bottom of the reservoir due to water being used as the injection method. These strategic placements of the injection and producing wells gives a greater surface area to produce from while maintaining the BHP.

Water is chosen for injection since gas is not economical out at sea and seawater was not an option. The producing wells are drilled horizontally along layer one which is the top layer. The perforations are placed evenly to allow a maximum surface area to produce from. This is done due to the reservoir not having a gas cap and wanting to use the water drive from the bottom of the reservoir. The injection well is a straight vertical well where the perforations are placed at the fourth layer. With this process we are able to produce from the top while injecting water from the bottom which will create a piston like affect and increase the recovery rate.

The location of where in the reservoir the wells are drilled are based off of the constraints when using a platform. The horizontal producing wells are placed in the middle due to the platforms location. This allows the horizontal wells to branch off from the platform to achieve a greater contact surface area of the reservoir. The injection wells are vertical for it is not economical to have a horizontal injector and the main purpose of the injector wells is to maintain a BHP which then helps the recovery process.

The project does have some criteria that has to be followed. For producing, the platform is not able to produce more than 1600 cubic meters cumulative. While the injection well has no out right limit. But the reservoir integrity must be kept in mind when injecting. The desire outcome of the injection is to have it assist in the recovery process, not to cause fingering or fractures.

Results

Numerous simulations were ran based on the constraints of one drilling platform with a max of 1600 cubic meters cumulative for all producing wells to find the highest recovery factor. Another constraint that was used was that the simulation for the field produced for twenty years. Out of the numerous well simulations six were chosen to show the effect of how and where the wells were drilled. To choose the best simulations we used certain criteria’s that are based on; water cut, oil recovery factor, and cumulative oil recovery. All simulations ran for twenty years and those that had an injector had an injection BHP of 70,000 kPa. All results are in Table 2.

The first simulation that was ran had a single vertical producer with no injector. This simulation is known as Producer1 (Figure 3, 4). With these physical parameters our recovery factor is 28%, cumulative oil recovery was 5.616 MMm^3, and 0% water cut. Based on the results we have not reached the potential from producing this field, for the reservoir simulations did not have a water cut. This indicates that the maximum production was not reached.

The second simulation that was ran had a single vertical producer and a single vertical injector. This was done to see if the injector could assist in the production. This simulation is known as Producer2 (Figure 5,). With these physical parameters our recovery factor is 34%, cumulative oil recovery was 6.7 MMm^3, and 0% water cut. Based on these results the injector did help in producing more and having a recovery factor. But the production is not at the full potential when producing from this field since there is still no water cut.

The third simulation that was ran had one horizontal producer and a single injector. This simulation is known as Producer3 (Figure 6, 7). With these physical parameters our recovery factor is 29%, cumulative oil recovery was 5.8 MMm^3, and 0% water cut. Based on these results the recovery factor is lower than Producer2.

The fourth simulation that was ran had two horizontal producers and no injector. This simulation is known as Producer4 (Figure 8, 9). With these physical parameters our recovery factor is 31.2%, cumulative oil recovery was 6.15 MMm^3, and 0% water cut. Based on these results the recovery factor is lower than Producer2 but higher than Producer1, and 3.

The fifth simulation that was ran had two horizontal producers and one injector. This simulation is known as Producer5 (Figure 10, 11). With these physical parameters our recovery factor is 44%, cumulative oil recovery was 8.7 MMm^3, and 4.2% water cut. Based on these results the recovery factor is higher as is the cumulative when compared to our best results so far. The water cut is not significant to cause too much of an alarm. So this is the best one compared to the previous simulations.

The sixth simulation that was ran had three horizontal producers and one injector. This simulation is known as Producer6 (Figure 12, 13). With these physical parameters our recovery factor is 43%, cumulative oil recovery was 8.45 MMm^3, and 95% water cut. Based on these results the recovery factor is higher than Producer1, 2, 3, 4. But it has a lower recovery factor and a higher water cut than Producer5.

Discussion

With these simulations we are able to see how an injector increases the recovery factor as do horizontal wells. The placement of injectors can also have an effect on the recovery factor and water cut. If the injector is to close to a producing well it will cause the producing well to only produce the injected water. The horizontal wells allow for a greater surface area contact when there are multiple perforations. This allows the wells to produce from a greater area of the reservoir as opposed to a vertical well.

The ultimate goal for this project is to find a simulation that has the highest recovery factor with the lowest water cut. The lower the number of wells the more economical the project will be. This shows that horizontal wells are the best option and that more than two does not increase the recovery factor. Another note is that the vertical wells had zero water cut for both scenarios with and without an injector. But they cannot recover nearly as much, so horizontal wells are still the best option for the producing wells. This is due to a greater surface area that the wells are producing from. All the values that were compared to find the best scenario are in Table 2.

With the constraints we are able to come to a confident conclusion that the best plan of action in producing from this field is two horizontal producing wells with one injector. This allows us to have a higher surface contact area to produce from. The producers will be placed in the top layer while the injectors are placed in the bottom layer. The injectors are placed in the bottom layer or layer four to create a piston like affect by pushing the oil in the bottom layers up to the producing wells. The purpose of the injectors is to keep the BHP high enough to prevent the well from dying off due to a lack of pressure. This plan gives us a high return and is realistic with using the present drilling platform.

Conclusion

The best simulation is Producer5. This simulation allows us to have a high recovery factor and a low water cut. This was found using a porosity of 20%, permeability of 20 md for I and J, permeability of 2 md K, with an oil saturation 75%, water saturation 25%, pay zone of 16 meters, and a hydrocarbon type of oil with specific gravity 0.77g/cc. The OOIP that was calculated in the first report is not the same as the OOIP that our recovery rate is stipulating. This is due to the simulation being more accurate in the calculations. Also with this program we are using constant parameters for the entire layer of the entire grid. This gives us a different recovery rate and cumulative oil recovery.

Although there are different enhanced oil recovery methods (EOR), we chose to just use water injection. The possible methods that we could have used are Chemical EOR, Combustion, Steam Flooding, Immiscible Flooding, and Miscible Flooding. These methods do have a criteria which is show in the figure below (Figure 1). Using the API equation and our specific gravity of 0.77 g/cc we get an API of 52.27. With this number and using Figure 1 we are able to determine that the only EOR method that can be used in this process is Miscible Fluid. So we go to Table 1 below to see if any of the miscible flooding properties can work. We compare our known parameters which are; temperature is 291.2 degrees Fahrenheit, API is 52. 27, porosity is 20%, depth of 3289-3353m, oil saturation 75%, sandstone formation, and permeability is 20md. After comparison, none of the miscible flooding types can be used for their criteria’s do not match the reservoir properties.

The conclusion of this part of the project is that water injection is the best method for this reservoir. All the possible EOR methods are either too expensive or their criteria’s do not match up to the reservoir properties. The next step in the project will be to calculate the cost to implement simulation Producer5 and compare it to the NPV using Producer5’s results. With this information we will be able to determine the future of the Fulmar field.

Figure 1 EOR Criteria

Table 1 Miscible Flooding Options

Nomenclature

NPV = Net Present Value

OOIP = Original Oil in Place

MDMSL = Measured depth from mean sea level

BHP= Bottom hole pressure

References

1. Marc M. Teeter, Omar Alkhuluiki, Riley Elliot, and Brandon Lovellette, Report 1 of Group 5 Senior Design, Missouri University of Science & Technology, Spring 2015

2. Nygaard Runar. “Lecture 3(Reservoir Simulation).” PE 4097: Senior Design. Missouri University of Science & Technology. Rolla, MO. Spring 2015

3. Nygaard Runar. “Lecture 4(EOR).” PE 4097: Senior Design. Missouri University of Science & Technology. Rolla, MO. Spring 2015

4. Figure 2 found in Lecture #3 Corrected reservoir sketch

Appendix of Figures

Figure 1 EOR Criteria

Figure 2 Vertical Well View

Figure 3 Producer1 Layout

Figure 4 Producer1 Cumulative Oil Recovery

Figure 5 Producer2 Cumulative Oil Recovery

Figure 6 Producer3 Layout

Figure 7 Producer3 Cumulative Oil Recovery

Figure 8 Producer4 Layout

Figure 9 Producer4 Cumulative Oil Recovery

Figure 10 Producer5 Layout

Figure 11 Producer5 Cumulative Oil Recovery

Figure 12 Producer6 Layout

Figure 13 Producer6 Cumulative Oil Recovery

Table of Figures

Table 1 Miscible Flooding Options

Table 2 Simulation Figures

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