Production Case Study Final

Production Technology 607

Group Project

Masters of Petroleum Engineering

Curtin Offshore Field- Project Proposal

Group 5

Lecturer: Dr. Mofazzal Hossain

Due Date: 3rd November 2014

Submission Date: 3rd November 2014

Transmittal Letter

We declare that this report- Curtin Offshore Field (Production Technology Project Proposal) is solely our own work. All references was cited and included into the reference list. All contributions made by others have been duly acknowledged.

Name : Rachael Lim Yiann

Student ID : 14898406

Individual Contribution: 20%

Name : Chong Mun Yee



Name : Leon Y J Kok



Name : Worapat Subanapas



Name : Timothy Bonavita



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Executive Summary The overview and purpose of this project involved the design and analysis of Curtin Offshore field

through the aim of producing from two reservoirs, J-16 and J-18. This involved determining the type of well and platform location, the well suspension, completion strategy and design. Although the well completion took into account both reservoirs, only a detailed analysis of the J-18 reservoir was done.

This task was accomplished through the utilization of the software “PIPESIM” to generate the necessary data to be able to analytically determine, by using engineering judgements, the optimum well design for producing the Curtin Offshore Field.

Initially, the first aspect of the field was a determination of well type and location. After considering the overall reservoir lithology as well as the reservoir and fluid properties, a vertical well completion with dual string production was established as the best design for producing though the two intervals. Once the well completion type was designed, an analysis of well suspension and completion had been developed. Underlying assumptions of J-16 and J-18 concerned the field production capability and stability. Thus, the dual string concept was adapted to be a segregated well producing from two intervals simultaneously. Furthermore, the completion well type was also suggested to be a cemented cased hole.

The project was then simulated through the use of PIPESIM software, namely that of the J-18 reservoir, generating a sensitivity analysis of suitable tubing size. Through PIPESIM analysis of varying the flow rate, water cut and GOR, the optimal tubing size was found to be 2.922 inches inside diameter. With the selected tubing size, operational flow at 3,303 B/D was determined.

Once the tubing size was determined an analysis was done on the effect of wellhead pressure and casing size. Through generated graphs, the optimum wellhead pressure was 200 psi. For the design of casing size, 9 inch inside diameter casing was selected to incorporate both J-16 and J-18 tubing in the same well. All the PIPESIM outputs and results of the analysis can be seen in the Appendix.

Future production analysis was theoretically evaluated as a section of the project, and artificial lift methods and water conning preventative treatments were taken into account. For the artificial lift system analysis, the future goals were mainly set under production rate, GOR and water cut which would be going to influence the whole reservoir. Through the ability to handle a variety of production rates, tolerance of solid production, flexibilities, operational cost and efficiency, gas-lift system was the preferred artificial lift system. Water coning prevention through the use of mechanical, operational and chemical treatments was assessed. Although there are many technical treatments available from the outcomes, it is suggested that maintaining production rate coupled with cementing treatment are recommended as the most reliable treatments.

The final aspect of the report was to develop the string completion design. In order to do this, all the information from the analysis performed needed to be taken into consideration when determining which components needed to be included. A basic dual tubing segregated system was used and then adapted to suit production requirements. The detailed design can be found in the Appendix with a detailed analysis of the depths of equipment in the report.

From the evaluation done, a number of recommendations were made to do with the design and running of the well system. Our overall recommendations and design are as follows:

Well should be a dual tubing, segregated, cement cased well system. The tubing size for the J-18 reservoir should be 2.922 inches inside diameter. Casing size should be 9 inches inside diameter. Well head pressure should be 200 psi. The operating flow rate is 3303 stb/d. If an artificial lift is implanted it should be of the gas lift type.

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Water coning should be controlled through operational flow rates and downhole cementing. The basic completion design is outlined in the appendix, figures 24 and 25 It is also strongly recommended to closely monitor the production data from the well. This

data will be essential in maintaining and controlling the well system in order to maximise the oil produced.

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Table of ContentsTransmittal Letter................................................................................................................................................ i

Executive Summary............................................................................................................................................ ii

1.0 Background/ Introduction............................................................................................................................1

2.0 Well Type and Platform Location..................................................................................................................3

3.0 Well Suspension and Completion.................................................................................................................3

4.0 Perforation Intervals and Location: J-18......................................................................................................5

PIPESIM..........................................................................................................................................................5

5.0 Sensitivity Studies.........................................................................................................................................6

5.1 Optimum Tubing Size................................................................................................................................6

5.1.1 Water Cut..........................................................................................................................................6

5.1.2 Gas Oil Ratio......................................................................................................................................6

5.2 Wellhead Pressure....................................................................................................................................7

5.3 Other Effects: Casing Size.........................................................................................................................7

6.0 Future Production Analysis...........................................................................................................................7

6.1 Artificial Lift..............................................................................................................................................7

6.1.1 Recommendations.............................................................................................................................8

6.2 Water Coning Control...............................................................................................................................8

6.2.1 Recommendation..............................................................................................................................9

7.0 Completion Design.......................................................................................................................................9

8.0 Recommendation and Conclusion..............................................................................................................11

References........................................................................................................................................................13

Appendix..........................................................................................................................................................14

1.0 Background/ Introduction

A wide range of design applications have been technically engineered in the petroleum industry, mainly aiming to maximize reservoir productivity under production uncertainties and constraints as well as economic standards. Completion design program, hardware, artificial lift methods and many series of facilities must be analysed, as a result of a constructive decision to drive the capacity of reservoir production.

The purpose of this case study report is to develop Curtin Offshore field by considering the ideal type of well and platform location, well suspension, completion strategy as well as tubing size selection in order to present a feasible completion design by considering artificial lift method and coning control strategy. Generally, Curtin Offshore field is sizable and consists of two main reservoirs of J-16 and J-18, the field is situated under 250 ft. of water and will encompass a permanently manned steel jacket platform. Additionally, other necessary field specifications are listed in the Appendix.

The objectives of this case study are:

1. To determine a suitable type of well and platform location.2. To select suitable perforation intervals and generate the inflow performance relationship. 3. To recommend a well suspension option and completion strategy.4. To determine the optimum tubing size. 5. To recommend a suitable artificial lift method coning control strategy. 6. To outline the proposed completion design schematic.

The scope of this case study report basically consists of the few areas listed below:

1. Well type and platform locationBased on the lithology and other related parameters, the ideal type of well and platform located is

specified by considering some of the issues and concerns that are directly related to the drilling, completion and production stage by considering the size of the well and casing. Besides, platform location is determined based on the location of the production and injection wells.

2. Well completion systemsProvides recommendation on the bottom hole completion option and casing strategy, depending on

the lithology formation and other parameters concerning drilling, completion procedures and production period.

3. PIPESIM multiphase flow simulationPIPESIM multiphase flow simulation software is utilized to perform sensitivity studies on tubing sizes,

water cut, Gas Oil Ratio (GOR)/ Gas Liquid Ratio (GLR) and wellhead pressure by nodal analysis. The optimum tubing and casing size is determined by analysing the simulation results through the generated plots.

4. Artificial lift strategy and coning control strategyThe artificial lift strategy is applied in order to improve well production. The studies of parameters to

be considered in the selection process of artificial lift is outlined and recommendations are provided based on the applicability of strategy to reservoirs J-16 and J-18.

5. Proposed completion designDevelopment of a completion design based on suitable components, design features and

approximate setting depths which is feasible according to requirements of J-16 and J-18 upon determining tubing size. The types of completion hardware are presented with justifications that are provided accordingly.

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Before continuing onto a grist of the studies, some underlying assumptions and general signposts are highlighted as below:

a) J-16 is an over saturated reservoir with initial sizable gas cap, denoting that the reservoir initial pressure is measured below bubble point, and hence will generate an IPR curve presenting two phase production flow rate.

b) J-18, situated at lower depth is an under saturated reservoir with no potential existence of gas cap, the reservoir initial reservoir measured above bubble point. Throughout the simulation techniques the reservoir will be analysed under these solid assumptions enabling only a single phase flow rate at the bottom of the wellbore, which generates a straight IPR curve line.

c) J-16 and J-18 intervals systematically share an infinite strong aquifer, and both reservoir are assumed to be driven by a strong water drive mechanism.

d) Although two reservoirs are observed in the Curtin Offshore field, a detailed analysis of J-18 will be presented in this project.

e) There are sections of shales that were defined as troublesome for drilling operators directly above J-16 intervals.

f) Artificial lift methods and water conning control were not supplemented in simulation program, however, comments, recommendations and the future improvements will be theoretically stated in the respective sections.

The deliverables of the case study is provided and outlined as below:

The major analysis of the project embraces an inclusion of well suspension and casing program, perforation intervals, the establishment of production line tubing dimensions through sensitivity analysis and a development of completion design as well as further improvement of possible artificial lift method and water conning control techniques. The main outcome of the research is determined based on an economic standard point. As such, recommendations and comments will be provided through the expected economic outcomes and benefits.

1. To determine a suitable type of well and platform locations.(i) Outline of the advantages and disadvantages of each type of well.(ii) Consider the formation lithology, interval thickness and reservoir properties.(iii) Consider reservoir location to determine platform locations.

2. To recommend a well suspension option, completion strategy and completion hardware.(i) Consider reservoir conditions and fluid properties.(ii) Production monitoring (iii) Consider the distance between reservoir locations.

3. To select suitable perforation intervals and generate the inflow performance relationship.(i) Determine perforation intervals based on J-18 through PIPESIM simulation.(ii) Consider water coning control technique.

4. To determine the optimum tubing size. (i) Sensitivity studies on different parameters by Nodal Analysis.(ii) Outline the other effects (Casing size) for long term production suitability.

5. To recommend a suitable artificial lift method.(i) Consider parameters used in determining the type of artificial lift.(ii) Provide recommendations on the ideal productions improvement.

6. To recommend coning control strategy. (i) Outline possibilities of water coning(ii) Outline the preventive measures of water coning(iii) Provide recommendations on the ideal treatment option.

7. To outline the proposed completion design schematic. (i) Provide list of components required in the completion design.(ii) Provide description of the functions and features of tools for the completion design

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(iii) Construct a basic configuration schematic at approximate setting depth.

2.0 Well Type and Platform LocationThe first aspect to consider of the field is the location and type of well system that is intended to

use. In order to determine which well type would best suit the system an analysis of the lithology and reservoir properties needed to be done. Firstly, the lithology of J-16 and J-18 consists of consolidated, well sorted, good porosity and permeability sandstone with minimal clay content. It also needs to be noted that J-16 has a small oil section. Although the data shows that J-16 reservoir is 100 ft thick, it also shows that the gas oil contact (GOC) is in this section. The GOC is 85 ft from the top of the J-16 reservoir, leaving only 15 ft of oil zone. There is also a section of 500 ft thick shale 700 ft above the J-16 reservoir which will be troublesome for drillers.

There are three main well types that is considered, that of vertical, deviated and horizontal. As the reservoirs are consolidated sandstone caving and sand production should be at a minimum. This left us with two main concerns when looking at the type of well, that of the troublesome zone and the thickness of the J-16 oil zone. As the section above J-16 is troublesome a comparison of drilling through to drilling around this shale needs to be considered. Troublesome shale is usually shale that is prone to swelling. This happens through the clay in the shale absorbing the water out of the drilling mud and swelling. This swelling can lead to a number of problems including that of caving. There are two solutions to this problem, that of using a specialised drilling fluid or using a deviated or horizontal well and drilling around the formation. Both methods have their problems associated with them. However, for the horizontal well we need to consider the thickness of the wells. As J-16 only has a 15 ft oil zone, there needs to be a high degree of accuracy in order to place a horizontal well correctly. This was deemed to be too problematic and as such the horizontal well was ruled out. This left us with the choice of a deviated or vertical well.

Similarly, drilling a deviated well is more expensive and the benefits of drilling one well are outweighed by the costs. The advantage taken into consideration of deviated wells is the drilling of the troublesome shale intervals that is made much easier. The main concern which separates these two wells is the drilling of the 500 ft. thick shale interval. Due to today’s drilling techniques and available technology, drilling through the shale will not cause significant concern. This can be done by using an oil based drilling fluid when drilling through the troublesome section or using a water based fluid with specialised additives. Once the troublesome shale section has been drilled the casing can be run down the well. Hence, the conventional vertical well is selected. Drilling vertical wells has much lower cost and complexity as compared to other types of well. Besides, vertical well has restricted accessibility of oil and gas which immediately surrounds the end of the well. Given that the pay zone for both reservoirs are only 15 and 60 ft. respectively, it is suggested to increase the production rate in withdrawing the oil before water breakthrough. This method could be feasible as both reservoirs share a common strong aquifer support.

By referring to the J-16 and J-18 reservoir schematic provided, it is suggested to construct two platforms in which both platform will be located approximately above the centre of each exploration wells. Based on estimations, there will not be large separation distance between the platforms. The injection well will extend as far down as the J-16 reservoir and is designed to inject gas into the reservoir in order to increase production. The production well will extend further down into the J-18 reservoir, but have perforations at two separate depths in order to produce from the J-16 and J-18 reservoirs.

3.0 Well Suspension and CompletionBeside the issues and concerns discussed earlier, the reservoir conditions and fluid properties of both J-

16 and J-18 are also being considered in determining the well suspension option. Although both the well system shared almost all the reservoir properties, however, J-18 can be seen to have no gas cap whereas J-16 does which means that J-18 is undersaturated while J-16 is saturated. This plays an integral part in

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deciding the completion of the well as J-18 is undersaturated means that it will flow into the well as a single phase whereas J-16 will be in a two phase state (oil and gas). Production monitoring is vital for both of this reservoir in order to keep the production flowing into the well as a single phase for J-18 whereas for J-16, production monitored is required to ensure that maximum oil can be retrieved via the gas injection as stated earlier. This means that both wells need to be produced separately in order to control the well dynamics and this will eventually narrow down the possible options to dual production or a dual well system. Besides this, a dual well system is also chosen due to the troublesome shale as drilling two separate wells at two different reservoir which only has a separation distance of 50 ft. would not be beneficial as it would be too troublesome and unfeasible from a cost perspective. In addition, two slant or deviated wells are not necessary since it is possible to drill into the formation directly from above.

For the purpose of separate production, a co-mingled tube was also ruled out and this left a final comparison between a single tubing annular flow and a dual tubing system. However, dual tubing system had been chosen as flow through the annulus is not desired because the well system has corrosive elements too it. Thus, the well suspension option will be a cased and cemented hole for J-16 reservoir and J-18 reservoir. In general, a suitable well diameter would be 12-1/4” ID and a suitable casing size would be 9-5/8” OD / 8.5” ID respectively. Therefore, the most applicable and ideal bottom hole completion option identified in this case would be a segregated well, cemented cased hole with dual tubing string completed with perforation and a liner.

Casing technical data

A typical piece of casing might be described as 9-5/8" 53.5# P-110 LT&C Rg 3: specifying OD, weight per foot (53.5 lbm/ft thus 0.545-inch wall thickness and 8.535-inch inside diameter), steel strength (110,000 psi yield strength), end finish ("Long Threaded and Coupled"), and approximate length ("Range 3" usually runs between 40 and 42 feet) (Technical Report 2008).

Considering the bottom hole completion option of open hole or cased hole completions, it is recommended to apply cased hole completions as it is widely used when there are several levels which can be proven in this case with J-16 and J-18 reservoir. Open hole completion is not normally preferred for oil wells as it is normally used when there is only one zone. Besides, conventional completions with production string (tubing) which is completely located inside the casing and that is not cemented, therefore easy to replace is suggested in this case. Since there are two pay zones, the usage of dual tubing’s are practically feasible. This is due to J-16 having a gas cap and a small pay zone of 15 ft. whereas J-18 having a larger area. As the two zones are different, there is a need to control both zones separately and in a different manner to ensure a maximized and economical production equipped with annulus packing.

A cemented liner with perforations is suggested as it allows for the most control of production zones. Since both reservoirs share a common strong aquifer support, gravel packing is suggested. This is due to the inevitable water production that will start during the lifetime of the well. As such, with increased water production sand production subsequently increases. Gravel packing will help to minimise the problems associated with the increased sand production.

Perforated completion is suitable when reservoir is required to be separated into intervals due to complicated geological conditions, such as gas cap, bottom water, water-bearing inter-bed or sloughing inter-bed (Renpu W. 2011). Furthermore, it is applicable when reservoir requires separate-zone testing, production, water injection, and treatments due to differences in pressure and lithology between separate zones (Renpu W. 2011). Perforated completion can also be applied when there is low permeability reservoir that needs massive hydraulic fracturing (Renpu W. 2011). It is also suitable for sandstone reservoir and fractured carbonatite reservoir (Renpu W. 2011).

The parallel tubing string completion from the multiple zone conventional completions functions as several levels produced in the same well at the same time but separately (i.e. through different strings of pipe) (Perrin D. 1999). The parallel dual string completion with two tubings, one for each of the two levels

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and two packers to isolate the levels from one another and protect the annulus (Perrin D. 1999). The benefits of Parallel dual tubing string completions are such as avoids problems in operation and production due to frequent wireline jobs and problems for safety and operation during workover (Perrin D. 1999).

4.0 Perforation Intervals and Location: J-18Once the well system had been determined, an analysis had been constructed on one of the reservoir

systems, that of the J-18 reservoir. In the analysis of the J-18 reservoir there was a variety of parameters that needed to be met. In order to do this analysis the program PIPESIM was utilised. Before the program could be utilised the perforation intervals needed to be determined.

For J-18 the OWC is directly below it, meaning that there will be water coning and hence an increasing water cut throughout the lifetime of the well. For now the well was decided to be cement cased and perforated near the OWC zone. The area decided to be perforate is roughly 15 ft above the OWC, placing the bottom perforation at 4375 ft TVDSS. This was due to water coning control techniques and will be discussed in the future production analysis section further on.

PIPESIM

For the next part of the analysis the program PIPESIM was used. For the setup of the well to analyse J-18, it was simplified by running the analysis as if it was a single well. Due to the chosen well completion being dual tubing segregated this was assumed to be valid for simulation purposes. Although this made the simulation easier, it needed to be remembered that the casing had to be large enough to account for both J-18 and J-16 pipes. The first stage of the analysis was to enter the well data needed to make a basic simulation. The programs inputs can be seen in detail in the appendix, figures 1-6. There are 5 main tabs that required input as the General, Artificial lift and Surface Equipment tabs were not used.

1. TubularsThe first part required the determination of the casing and tubing length and size. The casing

and tubing length were decided to be at the bottom and top of the reservoir respectively. This meant the bottom of the casing came to 4400 ft TVDSS and the tubing came to 4330 ft TVDSS. The size of the tubing and casing at this stage were set to 2.992 and 7.625 inch inside diameter respectively. These will be analysed later on.

1. Deviation SurveyThe deviation survey used was that of 250 ft as the well systems that we are analysing is

250ft under water.

2. Downhole EquipmentThe only downhole equipment used for the simulation was that of a packer, at 4330 ft

TVDSS.

3. Heat transferThe heat transfer tab require the estimation of the temperature of the soil at the well head.

This was assumed to be roughly 40ᵒF as the well is subsea.

4. CompletionsAs stated earlier, the perforations were assumed to be placed at 4375 ft. This tab also

required the input of fluid and reservoir properties. For the input of reservoir properties the Darcy IPR model was chosen. This was chosen as it had the most known parameters and would give the most accurate result. All the parameters were given in the assignment sheet and can be seen in the Appendix, table 1. From looking at the diagram provided and through the information given, it was decided to use a shape factor option of 19.1, which refers to a reservoir with strong water drive. The reservoir area of J-18 was assumed to be the same size as reservoir J-16, and from the sketch given

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was assumed to be 2200 acres. As J-18 reservoir had been chosen to analyse, the option “Use Vogel below bubble point” was left unchecked. As stated early, this is due to the system being undersaturated.

Once the reservoir properties were added in, this is continued by putting in the fluid properties. The properties given are detailed in the Appendix, table 2. From here an IPR curve was produced through a bottom hole nodal analysis and gave the graph shown in the Appendix, figure 7.

5.0 Sensitivity Studies

5.1 Optimum Tubing Size

For the next part of the analysis various tubing sizes were analysed and sensitivity studies done to determine the optimal tubing diameter. To do this a nodal analysis at the bottom hole was first used and the outlet pressure was assumed to be 200 psi, which would later be analysed. In the sensitivities tab the outflow sensitivity parameter chosen was tubing inside diameter. The range was that of 0.8-4 inch which was based on the API tubing standards available in the PIPESIM software, refer to table 3 in Appendix for API standard sizes available. Once this was done the simulation was run with the results are shown in figure 8 in the Appendix. From the graph it can be seen that there is a significant change in production for the first few tubing sizes, however, the larger tubing sizes converge at a certain flow rate. To further show the difference in the production rate a system analysis was done. The same setup was done, varying the tubing inside diameter and the results can be seen in the Appendix, figure 9. From the results it can be seen that the increase in the size results in a smaller and smaller increase in production rate. This means that the diameter at which the increase in the production rate is worth the cost of the wider tubing size needs to be determined. In order to do this the inside diameter sizes where then focussed from the 2.041 to 3.958 inch API standards and a system analysis was completed, giving the graph in figure 10. From the System analysis 3 tubing sizes were chosen to do further analysis on, that of 2.75, 2.922 and 3.476 inside diameters. A nodal analysis for these three sizes was completed, figure 11 in the Appendix, along with a table showing the resulting flow rate and bottom hole pressure, table 4 in the Appendix. Once the tubing sizes were selected 2 simulations were done to see how the tubing sizes would handle an increase in water cut and an increase in GOR.

5.1.1 Water CutTo analyse the effect of an increase in the water cut a nodal analysis was done. This was deemed

essential as the reservoir has a strong water drive and water breakthrough will occur during the production life. The water cut was varied in the sensitivities tab to different intervals ranging from 0-95%. The three tubing sizes gave the expected results through the nodal analysis, figures 12-14 in the Appendix. As can be seen, with increasing water cut the production rate decreased. This is expected as with an increase in the water cut the density of the solution is increased. This means that the maximum flow rate will decrease as the pressure gradient increases, meaning that there is less pressure differential between the top and bottom of the well system (Mofazzal 2014). Along with the reduction in overall flow rate, the oil rate itself will also decrease. It needs to be noted that all three tubing sizes could handle a water cut of 95%. This means that all tubing sizes will be able to handle the water increase and will still produce at high water cuts.

5.1.2 Gas Oil RatioOnce the water cut analysis was done a GOR nodal analysis was conducted. The result is displayed in

the Appendix, figure 15. As can be seen the tubing has an increase in liquid flow rate with initial increase in GOR. In order to determine the optimum GOR a system analysis was done, results are displayed in the Appendix figures 16-18. The maximum flow rate occurs at 1000, 1200 and 1400 for the increasing tubing

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sizes with liquid flow rates increasing by around 200 stb/d each. This is helpful for future production if an artificial lift or gas injection is implemented in the J-18 reservoir, details will be explained later.

From the above analysis, it was concluded that the optimal tubing diameter was 2.922 inches. This tubing size was chosen as all three tubings gave around the same response to the varying water cut and GOR analysis. Therefore, a tubing size that was cost effective was chosen. This was found to be the 2.922 inch tubing as it gave the best results for future aspects of production flow rates. The operating flow rate for this flow rate was determined to be 3303 stb/d, from figure 11.

5.2 Wellhead Pressure

The tubing size was then put into the design of the well in the tubing tab, and then a nodal analysis was run to see the effect of changing the wellhead pressure. The results are displayed in the Appendix, figure 19. As expected, the lower the wellhead pressure the lower the flow rate (Mofazzal 2014). This is due to there being a smaller differential between the top and bottom pressure, meaning that there is less driving force. The optimum wellhead pressure is therefore the lowest pressure available which is 200 psi.

5.3 Other Effects: Casing Size

There was also a simulation done on varying the casing size, figures 20 and 21 in the Appendix. Figure 21 is a magnified view of the graph to allow better analysis of the results. It showed that the casing has a positive effect on the flow rate up to a critical size and then it decreases. From the graph the tubing sizes of 7-10 inches give approximately the same results. This means that there is little difference in the flow rates and as such the smallest of these tubing sizes should be picked for the design as this will lower the cost. However, when considering the casing size production from J-16 via segregated well system was taken into account. This means that the casing size must be able to incorporate both the tubing of J-18 and J-16. Assuming that J-16 has a maximum tubing size the same as that of J-18, the casing needs to be a minimum of 7 inches. Taking this into account the tubing size is recommended to be that of 9 inches inside diameter. This will be enough to hold both the tubing’s as well as leave room for any artificial lift system that may be implemented later.

6.0 Future Production AnalysisAs part of the project there was to be two future studies done, that of the use of an artificial lift and

the effect and control of water coning and water shut-off. In order to do these studies, some theory is provided along with the recommendations. It should be noted that at this stage, the recommendations provided are based on what is expected to happen, however, the production data should be analysed throughout the life of the well and actions taken accordingly.

6.1 Artificial Lift

Artificial lift is a method approached to lower the producing bottom hole pressure (BHP) on the formation to increase production rate from the well completion. In this case study two methods were assigned in order to provide constructive strategies to ensure well production and future improvement. These are gas-lift and Electrical Submersible Pump (ESP) type artificial lift systems.

Generally, the procedure of selecting the artificial lift system is prioritized on maximum potential for developing the oil or gas field with the most economic value. The parameters that are used are:

Geographic location Capital cost Operation cost

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Production flexibility Reliability Mean time between failures

If the economic factors are not in concern the highest production value will be selected for artificial lift method. Apart from economic issue, well design consideration methods and factors must be taken into the account, which included reservoir properties, well productivity and well performance (5 Step to Artificial Lift Optimization).

However, for the future improvement, the most crucial issues that have to be considered are a decline change of the IPR curve and an increase in water cut throughout reservoir life expectation. The decline change of IPR assists operators to set a determined goal for future production rate and shut-in pressure. Likewise, water cut problems would also bring sand problems to the production which is not suitable for some types of artificial lift systems. A comparison of Gas-lift and ESP, based on J-18 actual and future predicted conditions, will be analysed as well as providing a recommendation (5 Step to Artificial Lift Optimization).

Depth of operation: The J-18 reservoir payable hydrocarbon zone is situated at the depth of 4375 ft. According chart provided, figure 22 in the Appendix, determination under production depth condition would potentially lead to the utilization of gas-lift due to the depth providing the highest production flow rate (Clegg, Bucaram, and Hein, N.W.J, 1993).

Production flow rate: After analysing IPR curve of J-18 field the operational flow rate was determined at 3303 B/D. As for the future analysis, one definite consideration is a decline in IPR curve throughout the life of the field which has to be set as a crucial goal for operators, shown in figure 23 in the Appendix. The main problem occurs when a decline in BHP and productivity index occurs. The flexibility of gas-lift technology exists as intermittent gas-lift has significant efficiency handling low volume of fluid with lower production rate. Furthermore, the ESP method can lift the high volume flow rates of the well, but at approximately 400 B/D, power efficiency drops sharply (Clegg, Bucaram, and Hein, N.W.J, 1993).

Water cut: This is one of the most important problems encountering late life reservoir which also eventually results in sand production in system. ESP method has the ability to accommodate for increased water cut by pressure maintenance and secondary recovery operations. However, this method will tolerate only minimal percentage of solid (sand) production. Conversely, gas-lift is the best among all artificial methods for handling solid material, but the power efficiency is relatively low for an increase in water cut at large operating depths (Clegg, Bucaram, and Hein, N.W.J, 1993).

GOR: The gas-Lift method is widely evaluated as the most excellent method for high formation GORs that have a strong water drive, whereas the ESP method is usually suitable for moderate GORs reservoir (Clegg, Bucaram, and Hein, N.W.J, 1993).

6.1.1 RecommendationsThe J-18 reservoir future goals were mainly set under production rate and water cut. For the case of

the J-18 reservoir the gas-lift method would be a better option due to the ability to handle a wider variety of production rates. Furthermore, at the determined operational depth there will not be any concern about the gas-lift not being able to handle higher water cuts or sand production. Considering the decline in IPR in the future, gas-lift would be the most suitable for the conditions as its flexibility converting between continuous and intermittent type. Overall, the operational cost, efficiency, flexibility, performance and others requirements of gas-lift are not completely away from the justification of ESP method, but under the assigned limited conditions gas-lift would presumably be the best option for the J-18 reservoir.

6.2 Water Coning Control

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As part of the analysis, both the possibility of water coning, watered out sections as well as prevention measurement had been considered. Generally, the main strategy for controlling water coning and watered out sections in well completion is classified into 3 categories, namely one short term and two long term options.

1. Operational treatment:

Usually the prevention from daily operation would be a primary strategy put into consideration. This is because a high rate of production would eventually result in an increased water conning problem. This comes from the viscosity force vertically overcoming the gravity force in high production rates. This can be diagnosed in rising water production and water cut at the top surface. A short term solution for limiting the water coning issues is to reduce the production rate to limit the extent of water coning. However, a long term solution is unavoidable to maintain production flow rate at desirable water cut percentage (Bill, Mike, Job, Jon, Fikri, Christian, and Leo Roodhart, 2000).

2. Mechanical treatment:

The most available technology for mechanical treatment application is implementing casing patch or an inflatable packer. These are often the solution of choice that ensure reliable well bore water shutoff. When the well has to be produced close to an aquifer regarding a strong water drive, such as J-18 reservoir, the casing patch is the desired water shut-off technique (Bill, Mike, Job, Jon, Fikri, Christian, and Leo Roodhart, 2000).

3. Chemical treatment:

Chemical treatment is a commonly used method in preventing water conning or isolating water zones, but requires accurate fluid displacement. Cementing and polymer gels are the key techniques used in the solution of water control. For cementing, the cement fluid is pumped through the casing for remedial treatment. Once the fluid sets the cement shows high compressive strength, extremely low permeability and high chemical resistance. The well is then re-perforated at a higher interval and the production recommences. Polymer gels are a highly effective method for near wellbore shutoff of excess water but unlike cement, gels can be squeezed into reservoir formation in order to provide water shut-off. Although gels can reduce water coning substantially it is still a developing technique (Bill, Mike, Job, Jon, Fikri, Christian, and Leo Roodhart, 2000).

6.2.1 RecommendationAlthough only a few common treatments were roughly pointed out in details, there is a variety of

treatment techniques available for mitigating water conning and zoning oil/water intervals. In the case of J-18 field, the most recommended treatment option would be that of chemical treatment, in particular cementing. Cementing is inexpensive compared to polymer gels and provides a more reliable solution.

7.0 Completion Design For this part of the project, both wells need to be considered. As the well is segregated, the

simulations will run separately, however, for the design, both the reservoirs need to be considered as they producing from the same well. During the previous analysis the casing size, tubing size and flow rates have been stated. For this next part a basic completion design will be determined. The basic configuration was adapted from the lecture notes (Mofazzal 2014).

The basic completion design of a dual tubing well system is comprised of two strings running from the surface to the first packer, that of a dual string packer. At this packer one of the strings will end, referred to as the short string, and the other string will continue until it reaches to the lower single string packer,

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referred to as the long string. In the case of our well system the short string will end when it reaches the J-16 reservoir, at an approximate depth of 4250 ft TVDSS. The Long string will then pass by two more single string packers, the upper and lower single sting packers, before ending at the J-18 reservoir at a depth of approximately 4360 ft TVDSS. The single string packers that will be used will be permanent production packers due to there being a shale zone in between the reservoirs, providing better zonal control.

The dual packer will be a retrievable dual packer. The dual packer will be at a depth of 4180 ft TVDSS which is at the top of the J-16 reservoir. The upper single packer will be bottom of the J-16 reservoir, a depth of 4280 TVDSS, with the lower packer being at the top of the J-18 reservoir, a depth of 4330 ft TVDSS. A sliding sleeve will be positioned in the shale zone between the reservoirs, approximately at 4300 ft TVDSS, as this will help circulate fluid to enable pressure control. To facilitate through-tubing operations a wireline re-entry guide will be placed on the long string below the packer but above the perforations, at about 4345 ft TVDSS. A no-go nipple will also be placed below the packer but above the perforations for both J-18 and J-16, which will be utilised for testing leaks in the tubing, at a depth of 4340 ft and 4240 ft TVDSS respectively. A seal assembly will be used at the upper single string packer, at 4280 ft TVDSS, which will be of the locator type. The locator assembly will provide a depth indication as well as prevent downward tubing movement.

A travel or slip joint will also be installed to accommodate tubing movement as well as expansion and contraction. In order to ensure maximum safety one will be installed above the upper single sting packer, at a depth of 4280 ft TVDSS, the other will be installed just below the surface, roughly 300 ft TVDSS. Both strings will also have a sub-surface safety valves (SSSV’s). The position of the valves needs to be a balance of factors, it cannot be too low due to the possibility of having too much hydrostatic pressure on it, but it needs to be away from the surface where it could potentially come to harm. They will be in a staggered configuration to ensure that they do not interfere with each other, with the long sting having the SSSV at 350 ft TVDSS and the short string at 375 ft TVDSS.

A blast joint is also recommended to be positioned across the J-16 perforations. This will help prevent possible erosion damage of the long string due to fluids and solids produced from the J-16 reservoir. Although the depth of perforations for the J-16 reservoir was not analysed, it is assumed to be in the oil section, hence at a depth of 4265-4280 ft TVDSS. Given that an artificial lift may be implemented later on in the well life, side pocket mandrels will be placed above the dual packer to enable such implementation. It is recommended to stager this configuration as it will provide better control for each of the production strings as well as avoid any string rubbing. These mandrels will be placed approximately 1200 ft apart, with the first being placed at 400 ft. This will provide a range of depths for the artificial lift injection later in the well life. A basic configuration schematic has been drawn up in the appendix, figures 24 and 25.

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8.0 Recommendation and ConclusionThe aim of this case study report is to outline the analysing achievement of Curtin Offshore field

throughout developing learning outcomes from Production Technology unit. Throughout the analysis of the Curtin Offshore Field there were certain assumptions and notable points that played an integral role in the outcomes and recommendations that we have made. These mainly are:

a) J-16 is an over saturated reservoir b) J-18 is an under saturatedc) J-16 and J-18 intervals systematically share an infinite strong aquiferd) There are sections of shales that were defined as troublesome for drilling operators directly above J-

16 intervals.e) Both reservoirs were assumed to have the same properties, that of reservoir and fluid properties.f) The simulation of the J-18 could be run as a single well system

The first part of this report outlines the guidelines that were used in order to determine the well type and location, as well as the completion of the well in question. Due to the small oil zone of the J-16 reservoir and the advancement in drilling technology, we concluded that the best well system for this field would be a vertical well. Furthermore, due to the problematic shale it was recommended to only drill one well which will have dual production of both the J-16 and J-18 reservoirs, namely that of a dual tubing well. The dual tubing was deemed a necessity as the properties of the reservoirs made the separate monitoring of the production data essential in order to maximise the volume of oil produced.

Following the determination of the well system a detailed analysis was done of the J-18 reservoir. In order to accomplish this analysis the program PIPESIM was utilised. Using PIPESIM the first analysis that was done was the choice of tubing size with the intention of balancing the maximisation of production flow rate with the economic cost behind it. In order to do this the API standard tubing sizes where used and a nodal analysis was done. The nodal point analysed was that of the bottom of the well. Through comparing the flow rates, the tubing sizes response to an increase in water cut and GOR, a tubing size of 2.922 inch inside diameter was chosen which will produce an operating flow rate of 3303 stb/d.

Once the tubing size was determined an analysis of the wellhead pressure and casing was done. The wellhead pressure response gave the expected results with the optimum pressure being that of the lowest pressure possible. This is due to the flow rate being directly proportional to the pressure differential, hence the larger the pressure differential the larger the flow rate. For the casing size there were a few aspects that needed to be considered. Firstly, when analysing J-18 reservoir, casing size that would optimise the flow rate need to be determined. From the results it was found that a casing size in the range of 7-10 inches inside diameter would accomplish this.

In order to determine which of these casing sizes would be ideal, the system as a whole as well as possible future implementations need be identified. As this is a dual tubing well, the casing size needed to be large enough to account for both the J-18 and J-16 production strings. On top of this there was also the possibility of an artificial lift system being implemented. Taking all this into consideration a casing size of internal diameter of 9 inches was deemed acceptable. This was considered the smallest casing size that will allow enough room for both strings, the possibility of an artificial lift as well as maximising production flow rates.

The next stage of the report summarises the future production analysis that was done, namely that of an artificial lift and water control. For the artificial lift analysis there were two main types that were being analysed, that of a gas lift and an Electrical Submersible Pump (ESP) system. From the available data, a comparison was done of the two systems of how they would handle the future problems that may arise from the production. Due to the likely increase in water flow, the decrease in production rates and the depth of operation it was concluded that the gas lift system would be best suited for the J-18 reservoir.

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For the water coning and water shut-off analysis a quick comparison of available technologies was established. There were three main treatments that were looked at, that of operational, mechanical and chemical treatment techniques. Although there are numerous methods within these categories, just few of the most readily available and widely accepted techniques were looked at. From the analysis done it was determined that the main problem for the J-18 reservoir will be that of water coning. In order to reduce the effect of water coning it was recommended that the flow rate be controlled in order to minimise the extent of the coning issues and when the water cut becomes too high that cementing downhole and perforating further up is the most adequate technique. However, as with the artificial lift systems, it is strongly recommended to analyse that production data during the life of the well to achieve a better analysis of the best treatment available.

The final section of this report outlined the recommended completion design of the production string. In order to do this completion design both well systems needed to be looked at as well as enabling any possible future operation to be achieved. The basic design was illustrated in figures 24 and 25 in the Appendix. The main points to note in this design are the travel joints, which are used to stabilise the strings in the well, and the staggered configuration of the side pocket mandrels, to account for future artificial lift systems. The rest of the completion is from a basic design obtained from the course notes from Production Technology 607 unit. The approximate depths of these components are detailed in the report.

Overall, through the analysis done, the well design recommendation are as follows:

Well should be a dual tubing, segregated, cement cased well system. The tubing size for the J-18 reservoir should be 2.922 inches inside diameter. Casing size should be 9 inches inside diameter. Well head pressure should be 200 psi. The operating flow rate is 3303 stb/d. If an artificial lift is implanted it should be of the gas lift type. Water coning should be controlled through operational flow rates and downhole cementing. The basic completion design is outlined in the Appendix, figures 24 and 25 It is also strongly recommended to closely monitor the production data from the well. This

data will be essential in maintaining and controlling the well system in order to maximise the oil produced.

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References

5 Step to Artificial Lift Optimization. Commercial presentation, Weatherford Artificial Lift Systems. Houston. http://petrowiki.org/Artificial_lift_selection_methods

Bill, Mike, Job, Jon, Fikri, Christian, and Leo Roodhart. 2000. Water Control. https://www.slb.com/~/media/Files/resources/oilfield_review/ors00/spr00/p30_51.pd

Claudio Alimonti. “Well Completion” Encyclopaedia of Hydrocarbon Volume 1, Exploration, Production and Transport.

Clegg, Bucaram, and Hein, N.W.J. 1993. Recommendations and Comparisons for Selecting Artificial-Lift Methods. J Pet Technol 45 (12) http://petrowiki.org/Design_considerations_and_overall_comparisons_of_artificial_lift

Eric, and Moji Karimi. 2011. “How Casing Drilling Improves Wellbore Stability” TESCO Corporation. American Association of Drilling Engineers.

Horizontal Highlights: Middle East Well Evaluation Review. 1995.

Mofazzal, Hossain. 2014. “Lecture Notes - Production Technology 607” PowerPoint lecture notes. Department of Petroleum Engineering. Bentley, W.A: Curtin University

Ozan Arslan. 2005. “Optimal operating strategy for wells with downhole water sink completions to control water production and improve performance.” A Dissertation of Louisiana State University.

Perrin, D. 1999. Well Completion and Servicing. Paris: Editions Technip.

Renpu, W. 2011. Advanced Well Completion Engineering. 3rd ed. Oxford: Elsevier

Technical Report on Equations and Calculations for Casing, Tubing, and Line Pipe used as Casing or Tubing; and Performance Properties Tables for Casing and Tubing. 7th ed. 2008. Washington DC: American Petroleum Institute.

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http://petrowiki.org/Design_considerations_and_overall_comparisons_of_artificial_lift

http://petrowiki.org/Artificial_lift_selection_methods

Appendix

Figure 1. Screenshot of Tubular tab from PIPESIM software

Figure 2. Screenshot of Deviation Survey tab from PIPESIM software

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Figure 3. Screenshot of Downhole Equipment tab from PIPESIM software

Figure 4. Screenshot of the Heat Transfer tab from PIPESIM software

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Figure 5. Screenshot of the Heat Transfer tab from PIPESIM software

Figure 6. Screenshot of Fluid Properties window from PIPESIM software

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Table 1. Reservoir Properties provided

J-18 Average Thickness 60 ftJ-16 Average Thickness 100 ft

Average Net to Gross (all) 90 %Porosity 24 %

Permeability 100 mDKw/Kh 0.5

Endpoint Kro 0.85Endpoint Krw 0.40

Sw 0.20Initial Reservoir Pressure 2000 psigReservoir Temperature 200 ᵒFReservoir Water Salinity 60,000 ppm

Table 2. Reservoir Fluid Properties provided

Oil Gravity 35 ᵒ APIViscosity at reservoir temperature 1.2 cP

Water viscosity at reservoir temperature 0.8 cPFormation volume factor 1.3 rb/stb

Solution gas oil ratio 400 scf/bblH2S content 10-20 Ppm

CO2 0.1 %

Figure 7. IPR graph of the J-18 reservoir.

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Table 3. API tubing sizes available in PIPESIM software

API Standard Tubing SizesOutside Diameter

(inches)Inside Diameter

(inches)1.05 0.824

1.315 1.0491.66 1.381.66 1.411.9 1.611.9 1.65

2.375 1.7032.063 1.7512.375 1.8672.375 1.9952.375 2.0412.875 2.1952.875 2.2592.875 2.3232.875 2.441

3.5 2.753.5 2.9223.5 3.0684 3.4764 3.548

4.5 3.958

Figure 8. Nodal Analysis of varying inside diameter of tubing, size range 0.8-4 inches.

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Figure 9. System Analysis of varying inside diameter of tubing, size range 0.8-4 inches.

Figure 10. System analysis of varying inside diameter of tubing, API sizes 2.041 to 3.958 inches

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Figure 11. Nodal Analysis of varying inside diameter of tubing, sizes 2.75, 2.922 and 3.476 inches.

Table 4. Operating Flow rate and pressure for 2.75, 2.922 and 3.476 inch tubing

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Figure 12. Nodal Analysis of 2.75 inch tubing with increasing water cut, 0-95%


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Figure 15. Nodal analysis of varying gas oil ratio from 400-2000 scf/bbl.

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Figure 16. System Analysis of varying gas oil ratio for 2.75 inch tubing


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Figure 19. Nodal analysis of varying well head pressure of 200-800 psia.

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Figure 20. Nodal Analysis of varying casing size from 5-12 inches

Figure 21. Magnified section of Nodal Analysis of varying casing size from 5-12 inches.

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Figure 22. Comparison of some artificial lift systems comparing production flow rates and depth of operation (Clegg, Bucaram, and Hein, N.W.J. 1993).

Figure 23. Expected trend in the IPR curve for a reservoir, showing a decrease in the liquid production through the life of the well (Clegg, Bucaram, and Hein, N.W.J. 1993).

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Figure 24. Basic completion diagram of the bottom of the well (Mofazzall 2014).

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Figure 25. Basic completion diagram of the top of the well (Mofazzall 2014).

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Documents

Production Case Study Final