Final Report for Chevron Vapor Recovery Unit Project

Transcription

1 Final Report for Chevron Vapor Recovery Unit Project Submitted to: Wesley Brubaker, Project Engineer Chevron Houston, Texas Prepared by: Leslie Esparza Krisha Mehta Sean Swearingen, Team Leader Mechanical Engineering Design Projects Program The University of Texas at Austin Austin, Texas Fall 2009

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3 Final Report for Chevron Vapor Recovery Unit Project Submitted to: Wesley Brubaker, Project Engineer Chevron Houston, Texas Prepared by: Leslie Esparza Krisha Mehta Sean Swearingen, Team Leader Mechanical Engineering Design Projects Program The University of Texas at Austin Austin, Texas Fall 2009

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5 ACKNOWLEDGMENTS Over the course of semester we received much guidance and technical advice from both the engineers at Chevron and the faculty at the University of Texas at Austin. We would like to extend our thanks to those who helped make our project possible and call attention to their contributions. First, we would like to thank Wesley Brubaker, Chris Kurr, and Zachary Schneider at Chevron for sponsoring our senior design project and giving us the key information and counseling necessary to execute our project. We would also like to think Dr. Crawford for heading the UT-SDP program which gives us and our classmates the opportunity to work on real world projects with major companies, such as Chevron. Dr. Kiehne, our Mechanical Engineering faculty advisor, provided us with valuable feedback on our project. Dr. Bommer, from UT s Petroleum Engineering department, was also kind enough to review our vapor recovery unit design and give us insight into critical problems that occur in the field during oil and gas production. Dr. Krueger, our graphics advisor, reviewed our reports helped us to improve their professionalism. John Montgomery, our teaching assistant, played a central role in our project s development and provided us with advice and coaching throughout the semester. i

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7 TABLE OF CONTENTS Acknowledgments... i Table of Contents... iii List of Figures...v List of Tables... vii Executive Summary... ix 1 INTRODUCTION BACKGROUND Chevron Project Overview Standard Vapor Recovery Unit PROBLEM STATEMENT REQUIREMENTS AND CONSTRAINTS Requirements Constraints SUBFUNCTION DEFINITION Function Structure and Morphological Matrix Patent Search DESIGN EMBODIMENT AND ANALYSIS VRU Design Overview Determining Gas Compression Stages Required Tank 1 Gas Compressions Feasibility Calculation Combined Gas Flow Compression Feasibility Calculation Interstage Cooling Water and Gas Phase Separation Equipment Drivers Valve Systems MATLAB Model Individual Component Design Compressors Compressor Selection Justification Design Calculations Gas Coolers Cooler Selection Justification Air-Cooled Heat Exchanger Design Gas-Liquid Separators Separator Selection Justification Vertical Separator Design Water Disposal System Drivers Compressor Drivers Cooler Drivers MATLAB Results and Sensitivities Separator and Cooler Results Compressor Results and Sensitivities iii

8 TABLE OF CONTENTS CONTINUED 6.5 Bill of Materials Solid Skid Model FINANCIAL ANALYSIS Annual Sales Loss Investment Costs Payback and Return on Investment Net Present Value COST ESTIMATE FUTURE WORK AND RECOMMENDATIONS CONCLUSION REFERENCES APPENDIX A: DESIGN FEASIBILITY CALCULATIONS... A-1 APPENDIX B: DETAILED VRU DESIGN FLOW DIAGRAM... B-1 APPENDIX C: MATLAB FLOW CHARTS... C-1 APPENDIX D MATLAB CODE... D-1 APPENDIX E: COOLER SAMPLE CALCULATIONS... E-1 APPENDIX F: VERTICAL SEPARATOR SAMPLE CALCULATIONS... F-1 APPENDIX G: GANTT CHART... G-1 iv

9 LIST OF FIGURES Figure 1. Production Platform Flow Diagram....4 Figure 2. Standard Vapor Recovery Unit Schematic....5 Figure 3. VRU Function Structure Figure 4. Air Cooled Exchanger with Wind Shields Figure 5. VRU Design Flow Process Diagram Figure 6. Single Stage Compressions from Tank Figure 7. Two Stage Compressions from Tank Figure 8. Combined Gas Flow Compression Figure 9. Compressor Chart Figure 10. Compressor Selection Chart Figure 11. Component Layout of Air Coolers Figure 12. Vertical and Horizontal Two Phase Separator Schematic Figure 13. Vertical Scrubber Design Dimensions Figure 14. Two Dimensional Skid Layout Figure 15. Three Dimensional Skid Layout Figure 16. Value of Recovered Gas vs. Natural Gas Spot Price Figure B.1. Detailed VRU Process Flow Diagram...B-1 Figure C.1. Main VRU MATLAB Program Flowchart...C-1 Figure C.2. Vertical Separator MATLAB Function Flowchart...C-2 Figure C.3. Cooler MATLAB Function Flowchart...C-3 Figure C.4. Heat Capacity Calculator MATLAB Function Flowchart...C-4 Figure G.1. Gantt Chart... G-1 v

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11 LIST OF TABLES Table 1. Specification Sheet: Function Requirements....7 Table 2. Specification Sheet: Constraints....9 Table 3. Thermodynamic Property Table Table 4. Compression stage flow rate and discharge pressures Table 5. Compressor Selection Decision Matrix Table 6. Condensate Water Piping Results Table 7. Sensitivity Cases Table 8. Separator Design Outputs Table 9. Cooler Design Outputs Table 10. Compressor Design Outputs Table 11. Bill of Materials Table 12. Past and Predicted Natural Gas Spot Prices Table 13. VRU Costs vii

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13 EXECUTIVE SUMMARY The Vapor Recovery Unit project focuses on one of Chevron s oil and gas production platforms in the Gulf of Mexico continental shelf. Our team s objective is to configure a Vapor Recovery Unit (VRU) for this platform that will increase two lowpressure gas flows to a sufficient pressure and re-route the gas to enter the sales stream. This system will compress gas coming from both an existing bulk surge tank on the platform as well as a new tank that has not yet been installed. Chevron wants to maintain compliance with applicable environmental laws and regulations to minimize gas losses and increase profits. To reduce hazardous emissions on the platform, an efficient and economical system is needed to capture hydrocarbon vapors which are currently being flared or burnt off into the atmosphere. Further detail on our project s background and design requirements can be seen in the Background, Problem Statement, and Requirements and Constraints sections of the report. Overall VRU and detailed individual component designs have been developed through research and analysis. Our final VRU design recommendation incorporates the following key components: gas compression and cooling, water and gas separation, piping systems for condensate water removal, equipment drivers, and key valve systems. Reciprocating compressors, powered by natural gas engines, are used for gas compression. Hot gas at the compressor outlet is cooled using air-cooled heat exchangers, which are powered by electric motors. Vertical liquid-vapor separators use gravity to separate condensate water from dry gas after cooling, where the water is piped from the scrubbers to a water collection point. The key valve systems include valves for the compressor inlet and discharge, control valves for the scrubber, and a three way valve to combine gas flows. Because of the significantly low gas pressures, multiple compression stages are needed considering individual and combined gas streams. As a result, three sets of compressors, coolers, and scrubbers are modeled in our overall VRU design. Thermodynamic feasibility calculations and justifications are presented to support our findings and component selections. A MATLAB computer model of our system provides design simulation and verification using engineering analysis. Equipment sizing and power specifications from the model, along with a compiled bill of materials, are used to create a solid skid model of our design layout for visualization. A full discussion of these topics concerning our overall VRU design and its key components can be seen in the Design Embodiment and Analysis section of the report. An important aspect of the proposed design solution is our financial analysis, addressing annual sales loss, investment costs, payback, ROI, and net present value. The Financial Analysis section in the report provides further detail on these topics. Based on average values, considering the short payback period of 4 months, high return on investment of 243%, and positive annual revenue of $4 million, our analysis shows implementing our final design solution is financially sound and would be a favorable investment for Chevron. ix

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15 1 INTRODUCTION The Vapor Recovery Unit project focuses on one of Chevron s oil and gas production platforms in the Gulf of Mexico continental shelf. Our team s objective is to configure a Vapor Recovery Unit (VRU) for this platform that will increase two lowpressure gas flows to a sufficient pressure to enter the sales gas stream. In addition to conveying our understanding of the project background and problem, we will describe and justify our decisions made when generating ideas for design. Our primary focus will be on outlining the design analysis, embodiment, and results for our final design model and individual component designs. Our team will discuss the financial analysis associated with our project solution, as well as provide recommendations for further solution improvements and future studies for the project. Also included in this report is a project Gantt Chart outlining our project time schedule, and a specification sheet detailing the project-specific design requirements and constraints for implementing a VRU system. 2 BACKGROUND 2.1 Chevron Our sponsor, Chevron, is a major oil and gas company that has over 62,000 employees and operates in over 100 countries. It is one of six super major oil companies that are involved in all aspects of upstream and downstream activities, including the exploration, production, refining, distributing, and marketing of hydrocarbons as finished oil and gas products. In addition to producing oil and gas,

16 Chevron is also involved with power production and is the world s leader in producing geothermal energy. Chevron also has mining and chemical production divisions and invests in researching renewable fuels. Outside of oil and gas production, Chevron is well known for its fuel additive Techron, which acts as a detergent and prevents engine build-up [1]. Chevron is one of the largest producers of oil and natural gas on the Gulf of Mexico shelf. In addition to being the largest lease holder on the outer continental shelf, Chevron owns 313 major structures in the Gulf of Mexico and in 2008 maintained an average daily net production of 76,000 barrels of crude oil, 439 million cubic feet of natural gas and 10,000 barrels of natural gas liquids. Working with engineers in Houston, TX and Covington, LA, our team will be focusing on one of Chevron s oil and gas production platforms in the Gulf of Mexico continental shelf [2]. 2.2 Project Overview Our project involves increasing the reliability and efficiency of gas production, presenting a unique set of cost drivers and environmental concerns due to its offshore location. Offshore equipment reliability is a high priority because loss of production and equipment replacement present financial liabilities for Chevron. Environmental factors are also of concern and Chevron wants to reduce its carbon emissions on this platform by recovering excess low pressure gas and adding it to the sales gas stream rather than burning it off, also known as flaring. Gas flaring and venting are highly regulated in the Gulf of Mexico by the Minerals Management Service (MMS). 2

17 Our team will focus on one of Chevron s offshore production platforms in the Gulf of Mexico, where oil and gas are produced and processed from underground deposits. A general flow diagram of this platform, as seen in Figure 1 on the following page, gives a basic overview of how oil, water, and gas are separated from the well streams. The gas and liquids flow from the well head through high, medium, and low pressure separators. The liquids, consisting of oil and water, eventually exit the low pressure separator and enter the oil dehydration unit. At this stage the water is sent for treatment to be dumped back into the ocean, while the dry oil is pumped to shore. The excess gas needs to be compressed to be sent to shore and must go through the inlet of the sales compressor. The high and medium pressure gas flows are at sufficient pressures to enter the second and first stages of the sales gas compressor, respectively. Currently, the excess low pressure gas must flow from the low pressure separator to a bulk surge tank, where the gas is then flared to the atmosphere rather than going through a Vapor Recovery Unit (VRU). This VRU would allow for excess low pressure gas to achieve a sufficient pressure to enter the first stage of the sales compressor, recovering some of the gas. 3

18 Liquid Flows Gas Flows Alternate LP Gas Flow Sales Compressor High Pressure Separator 1 st stg 2 nd stg 1000 psig Well Stream Medium Pressure Separator 200 psig Low Pressure Separator 35 psig Bulk Surge Tank VRU Clean H2O Dry Oil Oil Dehydration Flare to Atmosphere Figure 1. Production Platform Flow Diagram. Our project s focal point will be designing and analyzing a VRU system to add to the production platform. Currently, all of the excess low pressure gas is being vented to the atmosphere since there is no VRU installed on the platform. Additionally, due to other production platforms in the area being damaged from a hurricane, a larger volume of production will be brought to our platform to compensate for the incurred losses. Bringing more oil and gas to the platform places greater emphasis on maximizing productivity, efficiency, and the sales compressor s capabilities, while increasing the demand for other separating equipment. At the same time, environmental and cost factors need to be considered. Thus, adding a vapor recovery system to feed into the compressor will address these issues by capturing low pressure gas and compressing it to add to the sales gas stream rather than venting/flaring. Flaring less of the low pressure gas and 4

19 incorporating it into the sales stream will recover vapors and boost sales while maintaining compliance with applicable laws and regulations. 2.3 Standard Vapor Recovery Unit A standard VRU includes three key components including a suction scrubber, a compressor, and a liquid transfer pump (with its associated drivers). Figure 2 below depicts a standard single stage VRU attached to a crude oil storage tank. Initially, hydrocarbon vapors are drawn out of the storage tank under low pressure and sent to a suction scrubber which separates excess water from the gas. The condensed water is then sent back to the storage tank via the liquid transfer pump while the gas in the suction scrubber flows through a compressor. From the compressor, the vapors are metered and transported to either the sales gas line or back to the production facility to drive other equipment. The control pilot that separates the stock tank from the suction scrubber prevents the formation of a vacuum in the top of the stock tank by shutting off the compressor and allowing back flow into the tank [3]. Figure 2. Standard Vapor Recovery Unit Schematic [4]. 5

20 3 PROBLEM STATEMENT Our team will research various Vapor Recovery Unit (VRU) equipment to develop design recommendations and select the optimal configuration for incorporating a VRU system on the platform while meeting key design criteria. This VRU will need to compress excess low pressure gas coming from both an existing bulk surge tank as well as a new tank that has not yet been installed. This gas must be brought up to a sufficient pressure in order to enter the inlet of the sales gas compressor. 4 REQUIREMENTS AND CONSTRAINTS 4.1 Requirements The first page of the specification sheet shown in Table 1 outlines the functional requirements that we will use to gauge the success of our design. The first functional requirement listed is to reduce carbon emissions. This environmental factor, which is one of the key drivers for installing the VRU, will be achieved by taking low pressure gas that that would normally be burned off or flared and increasing its pressure so that it can be added to the sale s gas stream and sold or rerouted back to the platform for use on-site. Another significant requirement for this project is to bring the low pressure gas from the new bulk surge tank and add it to the gas from the existing bulk surge tank. This is done to recover the low pressure gas from a damaged facility by integrating it with a functional facility. 6

21 Other key requirements for the VRU include making it easy to install and minimizing its size and weight due to the limited space available on the platform. It is also important to ensure that the design operates within safe temperature and pressure limits. This will ultimately prevent the need for costly repairs and extend the useful life of the gas processing equipment that makes up the VRU. The VRU design must also be judged on its financial merits and should provide a cost-benefit to Chevron in addition to complying with environmental regulations. Table 1. Specification Sheet: Function Requirements. 7

22 4.2 Constraints The second page of the specification sheet, Table 2, details the five categories of constraints associated with our VRU design: pressures, temperatures, flow rates, equipment sizes, and gas properties. The specifications for some pressures, temperatures, and flow rates were determined by first locating where the VRU would be integrated with the existing equipment, and then looking up the relevant information from our facility s process and instrumentation diagrams (P&ID). The rest of the pressures, temperatures, and flow rates were found by asking our sponsor what could generally be expected from the additional low pressure gas that would be brought in from the damaged facility. The limitations on equipment size and placement can be found by looking at the equipment location diagrams for our platform. The gas properties found in the specification sheet were determined by reviewing the results of a gas sample analysis test and will be assumed constant for all further models and analysis. 8

23 Table 2. Specification Sheet: Constraints. 5 SUBFUNCTION DEFINITION 5.1 Function Structure and Morphological Matrix By linking the various energy, material, and signal inputs from the black box to key functional requirements, we were able to develop a function structure as shown in Figure 3. Some lessons learned from the function structure were based on available resources and cycles. We learned that gravity could be used as a key energy source for facilitating liquid and gas separation in the VRU. Also, the process of separating, compressing and cooling gas is iterative and will most likely require multiple stages. We 9

24 also learned that the process of transferring condensed water and compressing gas pressure may require a driver. Due to the flow process, if one of the components fail, the entire process will need to be shut down until the component is repaired. Figure 3. Function Structure of VRU. A morphological matrix was created to review all possible ways to achieve the desired subfunctions from the function structure. We used the morphological matrix as a tool to discover new technologies and determine which components we could recommend for future VRU configurations. We were also able to use the matrix to select which components we would like in our final VRU design. 10

25 5.2 Patent Search Throughout the design process our team has performed a patent search to generate ideas for selection and design of VRU components and alternative vapor recovery systems. The following section is a description of two patents that we found to be the most relevant for the systems we considered in our project design. The first patent, Air Cooled Exchanger, describes an improved air-cooled heat exchanger with shields attached to each tube bank to deflect wind entering the exchanger without affecting cooling air flow on the tube exterior [5]. This proposed system seen in Figure 4, which has shields comprised of a wind deflecting front wall and triangular side walls, would be advantageous for improving control of exchanger operations in difficult weather with high wind velocities. This invention is significant for the project because certain design aspects were adopted for modeling the inter-stage gas coolers in our VRU system. It also provided insight into reflecting adverse atmospheric conditions in our design sensitivity analysis, which is especially relevant considering our project s offshore location. Figure 4. Air Cooled Exchanger with Wind Shields [5]. 11

26 The second patent, Eductor System and Method for Vapor Recovery, outlines a system for recovering discharged vapors from hydrocarbon processing systems to prevent or minimize harmful emissions [6]. This design uses venturi eductor technology to combine a high-pressure motive fluid with low-pressure vapors to discharge gas at an intermediate pressure and inject it into existing process equipment. Considering our project s objective of economically capturing hydrocarbon emissions, while maintaining Chevron s compliance with environmental regulations, this non-mechanical alternative vapor recovery system is relevant for our project s gas production and processing application. However, due to the lack of a high-pressure gas source on the offshore facility, we have only utilized this idea for future project recommendations. 6 DESIGN EMBODIMENT AND ANALYSIS 6.1 VRU Design Overview After reviewing our function structure, standard vapor recovery unit designs, and input from our sponsor we created the VRU layout shown in Figure 5. The thermodynamic properties associated with states 1-9 can be found in Table 3. The following sections will outline the process that led us to this design. 12

27 Figure 5. VRU Design Flow Process Diagram. Table 3. Thermodynamic Property Table Determining Gas Compression Stages Required The first step toward creating a vapor recovery unit is to become familiar with the process of natural gas compression. The Handbook of Natural Gas Transmission and Processing (HNGTP) provides much information on the subject and served as our source for determining the number of compression stages required for the gas flows from each of our two stock tanks. In particular, the handbook recommends keeping the compression 13

28 ratio for each stage of compression less than 4. This prevents the gas from reaching critical temperatures in excess of 300 o F which will damage compressors [7]. To create our design we performed design feasibility calculations for both the 5-45 psig gas compression from stock tank 1 and the psig gas compression for the combined 3MMSCFD flow stream Tank 1 Gas Compression Feasibility Calculation Figure 6 details the thermodynamic constraints associated with gas compression from tank 1. Figure 6. Single Stage Compression from Tank 1. Assuming negligible changes in potential and kinetic energy and adiabatic compression, the first law of thermodynamics reduces to [7]: If we assume constant specific heat for the gas, the isentropic outlet temperature can be found by the relation [7]: 14

29 Where (P 2 /P 1 ) is the compression ratio, K is the gas heat capacity ratio, and T 2s is the isentropic compressor outlet temperature. Once the isentropic temperature at the compressor outlet has been determined the actual outlet temperature can be found from the relation [7]: Where η c is the isentropic compressor efficiency which we have assumed to be 83% for a reciprocating compressor [8]. As expected, the outlet temperature for the compressor was in excess of 300 o F. With this in mind we decided to add a second compression stage and an interstage cooler to the design as seen in Figure 7. Figure 7. Two Stage Compression from Tank 1. To minimize the compression ratios across the compressors we decided to make each of the compression ratios three, resulting in an intermediate pressure of 15 Psig. 15

30 From the Handbook of Natural Gas Transmission, we found a rule of thumb relation that said that interstage air cooling could result in output cooler temperatures of 25 o F above ambient temperature. Assuming Steady State Steady Flow isentropic compression and negligible pressure drop across the cooler, we followed a similar procedure to the single stage compression and determined the intermediate temperature T 3 as well as T 5. This procedure resulted in compressor operating temperatures safely below the critical temperature of 300 o F. The detailed calculations for both single and two stage compression feasibility can be found in Appendix A Combined Gas Flow Compression Feasibility Calculation Figure 8 details the thermodynamic constraints associated with the combined gas flow from tank 2 and tank 1. Figure 8. Combined Gas Flow Compression. Performing the same calculation as the single stage compression from tank 1 we found that the compressor operating temperature was safely below the critical temperature of 300 o F. This makes it clear that only one compression stage is required for the combined 3MMSCFD gas flow from 45Psig to 90Psig. The feasibility calculations for this section can also be found in Appendix A. 16

31 6.1.2 Interstage Cooling The interstage coolers CLR 1-3 on Figure 5 are included in the design for the purpose of both lowering the potentially damaging high temperatures associated with gas compression and minimizing the horsepower requirements for the compressors. As we have mentioned before, gas flows over the critical temperature of 300 o F can damage equipment especially by degrading lubricants used in compressors [7]. Minimizing compressor power requirements is another important consideration in our design and interstage cooling decreases the temperature of the gas entering the compressor which in turn decreases the power required to run the compressor [7] Water and Gas Phase Separation Since water is an incompressible fluid, large quantities of water vapor in a natural gas flow stream can have catastrophic effects on gas compressors. To extract water from natural gas, two phase gravity separators (also called scrubbers) are often used in gas processing and our design includes one before every compression stage. Initially, our design also included scrubbers after each stock tank, but we were informed by our sponsor that they were not required because the stock tanks included mist extractors that removed excess water. Since condensate water is produced by each of the three scrubbers in our design it is necessary to transport the excess water to a holding tank to be cleaned and disposed of. On the bottom deck of the production facility where the VRU will be installed, there is a holding vessel called a sump tank where excess water produced at the facility can be stored. Since the VRU will be installed on the top deck of the facility, condensate water will be piped from the scrubbers to the sump tank using 17

32 gravity and internal scrubber pressure as a driving force. It is important to note that we have assumed that changes in pressure, temperature and volumetric gas flow rates across the scrubbers will be negligible Equipment Drivers Compressors and coolers are the only two pieces of equipment in the VRU that require an outside power source. As a requirement from our sponsors, the compressors in the VRU will be powered with natural gas drivers. These natural gas drivers typically come in the form of internal combustion engines and will provide power to all three of our compressors. The cooling systems typically have a low horsepower requirement and will be powered electrically from the production facility Valve Systems To set limits on the scope of our design we have decided not to design the valves in the VRU in detail but to simply show the placement of key valve systems in a detailed VRU design flow diagram found in Appendix B. There are three key valve systems found on the VRU design in Appendix B including compressor valves, scrubber valves and a three way valve. In order to control fluctuating gas flows and prevent damage, each compressor in the VRU is equipped with an inlet valve and discharge valve, labeled CIV and CDV respectively. In addition to controlling gas flows through the use of a pressure control valve (PCV), scrubbers must also be able to control the condensate liquid flow to the sump tank. This will be achieved through the use of a liquid control valve or LCV. A three way valve between state 7 and 8 on the VRU flow process diagram will be used 18

33 to combine the gas flows from stock tank 1 and 2 so that they may enter the final compression stage. 6.2 MATLAB Model A critical aspect of our engineering analysis for the project was to apply principles of thermodynamics, heat transfer, fluid mechanics, and gas separation to verify our proposed VRU configuration. As a result, we have created a computer model to simulate our developed VRU design using MATLAB. From this model, we automated our final design and obtained significant outputs by running simulations with varying key parameters. It also allowed us to examine and evaluate each individual component design in greater detail and adjust assumptions made as necessary. This feature facilitated the troubleshooting process for our design since each key component is modeled as a separate entity that can be modified individually. These computer simulations provided us with a collection of valuable data for our design: temperatures at all key states including compressor outlet temperatures; compressor and cooler brake horsepower to determine overall power required to drive the system; scrubber and cooler sizing specifications; and effects of deviating ambient temperatures, and flow rates. Some of this data, particularly the power requirements and dimensions, were important factors in sizing our VRU system for the platform and determining capital expenditure cost estimates for our financial analysis. The inter-stage coolers and vertical separators in our VRU configuration are modeled as separate sub-functions that are called in from the main MATLAB function, where the overall VRU program incorporates the isentropic compression analysis of the three compressors to reflect different compression stages in our design. The MATLAB 19

34 flow chart for the main function can be seen in Appendix C.1, while the separator and cooler flow charts are in Appendices C.2 and C.3, respectively. Another function was created to calculate the specific heat capacity of the gas at variable temperatures, using both the specific heat polynomial expression and, assuming the gas is treated as an ideal gas mixture, mass composition for the individual gas components. This function, whose MATLAB flow chart can be seen in Appendix C.4, proved to be extremely beneficial in easing the automation process of our model algorithms. The MATLAB code for these four functions can be seen in Appendices D.1-D.4. The key input variables for our program included the temperatures, pressures, and flow rates of the gas streams from both stock tanks, as well as the specific gravity and molecular weight of the gas. To verify the feasibility and output values of our model, we produced sample calculations for the compressors, coolers, and scrubbers, and provided justifications for assumptions made in our analysis; these calculations can be seen in Appendix A and Appendices E-F. Each of these components will be discussed in further detail in the next section of this report. 6.3 Individual Component Design Compressors Compression is the central element in VRU design and successful compressor selection is vital to a VRU s operation. Figure 9 divides natural gas compressors into three distinct groups: positive displacement, dynamic, and thermal type compressors. Though ejectors have been used in onshore gas pressure boosting, they require a high 20

35 pressure motive gas flow that is not available at our offshore site and will not be considered in our compressor selection Compressor Selection Justification Figure 9. Compressor Chart [8]. The Gas Processors Suppliers Association Engineering Data Handbook is a valuable resource for compressor selection and provides many useful charts and tables that compare various gas compressor types across wide volumetric flow rate and pressure regimes. Figure 10 compares reciprocating, rotary, centrifugal, and axial compressors based on their ability to handle various input flow rates and discharge pressures. When the flow rates and discharge pressures for each of the three compression stages are plotted on Figure 10 below, it becomes apparent that reciprocating, rotary, and centrifugal compressors are all acceptable choices. For offshore gas processing however rotary compressors are rarely used so we will further limit our compressor selection to only reciprocating and centrifugal compressors [8]. 21

36 Figure 10. Compressor Selection Chart [8]. Table 4. Compression Stage Flow Rate and Discharge Pressures. Though reciprocating and centrifugal compressors are both capable of increasing the pressure of natural gas, they operate under different mechanical principles which give rise to different operating characteristics. Reciprocating compressors, which consist of a piston that compresses gas in a fixed volume cylinder, tend to have lower capital costs 22

37 and power costs than centrifugal compressors while maintaining higher adiabatic efficiencies [8]. Centrifugal compressors, which use radial impeller movement to increase the pressure of a gas stream, require less maintenance than reciprocating compressors (due to having fewer moving parts) and have lower installation costs [8]. The benefits of each compressor type are summarized in Table 5 below. Since adiabatic efficiency and maintenance are both key concerns in compressor selection, there is no clear choice based on the aforementioned criteria. After running our MATLAB model for each type of compressor we found that the brake horse power (horse power adjusted for mechanical losses) requirements for the compressors were similar (within 5%), which also prevented us from using power requirements as a deciding criteria. Our final decision to use reciprocating compressors came after finding that using centrifugal compressors led to higher interstage temperatures, resulting from their lower adiabatic efficiencies. Since larger coolers are needed to offset the damaging high interstage temperatures and production floor space is limited, we found reciprocating compressors to be the preferred choice. Table 5. Compressor Selection Decision Matrix. 23

38 Design Calculations Brake horsepower (BHP) is the primary parameter for compressor design. The formula for calculating BHP can easily be adjusted to model reciprocating or centrifugal compressors, and is given below [7]: Where Z avg is the average compressibility factor; Q G,SC is the standard volumetric flow rate of gas (MMSCFD). T is the compressor suction temperature (R). P 2 and P 1 are the discharge and suction temperatures (Psia). E is the parasitic efficiency (for reciprocating: , for centrifugal: 0.99), and η is the compression efficiency (1 for reciprocating, for centrifugal units) [7] Gas Coolers Gas coolers are typically used as intercoolers for multiple compression stages or for compressor suction and discharge [9]. Gas cooling is a significant aspect of our VRU design by helping prevent equipment damage and lower compressor power requirements. These coolers cause minor pressure losses of the gas depending on the design [7]. However, for our design this pressure drop is considered negligible and gas cooling is assumed to be done at constant pressure. Based on our research, calculations, and selected cooler size, this critical assumption can safely be made and has been approved by our Chevron sponsors and faculty advisor, Dr. Thomas Kiehne. 24

39 Cooler Selection Justification The two primary types of cooling media used for gas cooling are air and water, where air cooling is achieved by air-cooled heat exchangers and water cooling is typically done using water-cooled heat exchangers or cooling towers. Since water has more favorable thermal properties than air, water coolers have a higher cooling capacity and require less heat-transfer surface area [8]. However, because water coolers require an adequate supply of cooling water, they have significantly higher operation and maintenance costs due to water pumping, treatment, and disposal [10]. Other concerns associated with water coolers include equipment corrosion and limited water availability, while air coolers require less frequent cleaning and have unlimited air quantities available with no preparation costs [11]. Although seasonal variations in ambient temperature can make temperature control difficult, air has become the more viable and economical heat transfer media for achieving industrial cooling requirements [8]. Overall, air-cooled heat exchangers are viewed as more cost-effective than water coolers over the system s projected lifespan, especially with their well-established and reliable design [8]. Considering our project s low design pressures, temperatures, and flow rates, as well as other factors including offshore location, cost sensitivity, and strict environmental regulations in the Gulf of Mexico, air-cooled heat exchangers are the ideal choice for modeling our cooler designs Air-Cooled Heat Exchanger Design The fundamental principle behind air-cooled heat exchangers (ACHEs) involves transferring heat from the gas to a cooling ambient airstream via finned tubes, where air movement is achieved by mechanical fans [11]. ACHEs consist of the following basic 25

40 components: tube bundle, axial fan, fan drive assembly, and supporting structure [8]. Hot gas flows through tubes in the tube bundle, the heat-transfer device for the cooler, where fins are applied to increase heat-transfer effectiveness by providing an extended surface on the air side [12]. We used the most typical fan configuration for our design, known as forced-draft, where the fan below forces air up across the tube exterior; a basic layout of this configuration can be seen in Figure 11. Figure 11. Basic Component Layout of Air Coolers [9]. To optimally model our three cooler designs, we assumed standard values in terms of tube geometry and tube bundle layout. These assumptions include fin length and spacing, tube pitch and diameter, and the number of tube passes and rows [12]. To keep the designs conservative we used a minimum ratio of 0.40 for fan coverage, which measures air distribution across the tube bundle face [8]. Using the ACHE design procedure outlined in the GPSA Engineering Data Book, we determined the key sizing and power requirements to model the coolers. These parameters, along with our cooler results, will be discussed in detail further along in the report. The key principles 26

41 underlying ACHE thermal design involve basic heat transfer analysis, where heat and material balances are performed for the air and gas sides of the exchanger. The heat dissipated by the gas (Q gas ), absorbed by the air (Q air ), and transferred from gas to air (Q) are all equal [9]: Q gas = Q air = Q which can also be expressed as [9]: m gas Cp gas ΔT gas = m air Cp air ΔT air = U A F (LMTD) where m is the mass flow rate, Cp is the specific heat capacity, ΔT is the temperature change, U is the overall heat-transfer coefficient, A is the heat transfer area, F is the LMTD correction factor, and LMTD is the log mean temperature difference that acts as the driving force of heat transfer. Using the relationship above, we calculated the total extended surface heat transfer area and converted this value to a bundle face area depending on the tube geometry and bundle layout. These parameters also allowed us to calculate the air mass flow rate and velocity. The minimum fan area and fan diameter were calculated using the bundle face area and fan coverage ratio. To determine the total pressure loss across the fan, we summed the calculated dynamic fan and air static pressure drops. Finally, the fan driver brake horsepower was estimated using average fan and speed reducer efficiencies, total fan pressure drop, and the actual volumetric flow rate of air at the fan inlet [8]. Sample calculations and key assumptions detailing this cooler design methodology are outlined in Appendix E. 27

42 6.3.3 Gas-Liquid Separators Liquid-vapor separators are one of the most common types of process equipment. As discussed in the VRU design section of the paper, water vapor extraction is crucial for prolonging compressor life and preventing equipment damage. Though there are three main types of gravity phase separators (horizontal, vertical and spherical) we will be limiting our discussion to horizontal and vertical scrubbers because spherical separators are only used for high pressure service which does not apply to our project constraints [8]. For both horizontal and vertical scrubbers, gas-liquid separation is accomplished in three stages. Primary separation, section A in Figure 12, occurs when incoming gas hits the inlet diverter plate causing large water droplets to coalesce and fall into section D from gravitational forces. In section B, secondary separation takes place as gravity causes the smaller water droplets in the gas flow to fall through the disengagement area into section D. Finally, the smallest droplets of water are collected by the mist extractor in section C before the gas exits the separator [13]. 28

43 Figure 12. Vertical and Horizontal Two Phase Separator Schematic [8] Separator Selection Justification Though vertical and horizontal separators achieve gas-liquid separation in the same manner, they have inherent advantages and disadvantages from one another that make them ideal for different situations. For example, vertical separators are ideal for offshore applications because they require less production floor space than horizontal separators. It is also easier to clean vertical separators and control their fluid levels [7]. Horizontal separators, on the other hand, are ideal for applications where large volumes of gas and surging are key concerns [7]. Since floor space on the production facility is severely limited and we do not require a separator that can handle large throughputs and surging volumes, we have decided to implement vertical separators in our design. 29

44 Vertical Separator Design When designing a two phase separator, the key dimensions required include the inner vessel diameter and seam-to-seam height. Other important dimensions include the liquid level height and vessel wall thickness. After reviewing numerous sources on separator design, we found a paper by Svrcek that takes multiple industry standard separator sizing methods and streamlines the process into a simple step by step methodology. A brief outline of the steps required to size a two phase separator will be covered here while the detailed sample calculations can be found in Appendix F. The first key dimension that must be calculated is the vessel diameter and it is found by the relation [13]: where Q V is the volumetric flow rate of gas in ft 3 /sec and U V is the vertical terminal vapor velocity of a single water droplet falling through the disengagement area of the separator in ft/sec. Once the vessel inner diameter has been found, the seam to seam height of the separator H T in Figure 13 must be determined, where H T is simply the sum of the heights H D, H LIN, H S, H H, H LLL and 1.5 ft. The lower liquid level height (H LLL ), distance between inlet nozzle and liquid level (H LIN ), and distance between inlet nozzle and mist extractor H D are easily determined from pressure dependent sizing charts given in the paper by Svrcek. Other heights that deal with the liquid level in the separator such as H S and H H, require more detailed calculations and are outlined in Appendix F. 30

45 Figure 13. Vertical Scrubber Design Dimensions [13] Water Disposal System To transport the condensed water coming out of the water separators and exiting the VRU system, we found the most viable and economical choice for our project would be to model a piping system that disposes the water into a sump tank, which is a mass tank vessel at atmospheric pressure that contains collected water from other equipment on the facility. Since water flow from our three scrubber designs is substantially low, we eliminated the need for liquid transfer pumps and their associated drivers in our system, simplifying our overall VRU design. Instead, this piping system uses the pressure difference from gravity to push the liquids out of the scrubbers and into the sump tank, 31

46 which is currently located on the bottom deck level of the platform. According to Chevron, our VRU system will be installed above the tank, allowing us to utilize this height difference and use gravity as the key driving force of this piping system. Our analysis for determining the required pipe sizing for each scrubber s water flow in our design was based on applying Bernoulli s principle, assuming an incompressible and non-viscous water flow. Standard pipe sizes vary from ½ to 2 in diameter with ½ increments, as per Chevron. We have also accounted for pressure losses in the pipe due to friction, which depends on the average water velocity, pipe length and diameter, and a friction factor obtained from the Moody diagram. The friction factor is based on pipe roughness and the Reynolds number for determining turbulent or laminar flow [9]. To account for losses from expected bends and valves in the piping, Chevron has provided us with an equivalent pipe length of 300 ft from each scrubber to the sump tank for our calculations. Using Bernoulli s equation to combine the fluid energy in terms of elevation (h), velocity (v), and pressure (P) between the scrubber and sump tank, the total energy can be expressed as [9]: P 1 + ½ ρv 1 ² + ρgh 1 = P 2 + ½ ρv 2 ² + ρgh 2 + P loss The pressure loss, using the D Arcy-Weisbach Equation, is expressed as [9]: P loss = (f L eq /D)(½ ρv avg ²) where f is the friction factor, L eq is the equivalent pipe length, D is the pipe diameter, and v avg is the average water velocity in the pipe. For the height difference between the 32

47 scrubbers and sump tank, we assumed the VRU would be installed two deck levels above the tank based on our system s skid dimensions and the equipment location diagram of the platform. Provided that the pipe inlet at the sump tank is located 6 from the bottom as per Chevron, and using the known height of 18 per deck level, we calculated the elevation difference to be Using these equations and assumptions, along with the pressures and calculated water velocities for each scrubber, we created an Excel spreadsheet to determine the average water velocity in the pipe for each scrubber design at different standard pipe diameters. These results are summarized in Table 6. Table 6. Condensate Water Piping Results. The feasibility analysis of our piping system was based on ensuring that the water velocity in the pipes remained between 5 to 15 ft/s to avoid pipe damage. According to Chevron, high water flows cause pipe erosion, while low velocities cause pipe corrosion. Using our data in Table 6, we were able to select the feasible pipe diameter for each scrubber depending on which average pipe velocity fell within this velocity range. As a result, both scrubbers 1 and 2 require ½ diameter piping, while scrubber 3 requires a 1 pipe diameter for water condensate removal. 33

48 6.3.5 Drivers In order to power our compressors and air coolers, we need to look at what types of drivers are applicable for our designs Compressor Drivers Gas compressors are typically driven by electric motors, gas engines, or gas turbines. While electric motors must rely on the availability of electric power, both gas engines and gas turbines can use pipeline gas as fuel. Since an abundant supply of natural gas fuel already exists on the production facility, we have only considered engines fueled by natural gas to drive the compressors in our VRU design. We have also discussed this decision with our sponsors at Chevron and have received their approval Cooler Drivers Fan drivers for air-cooled heat exchangers are typically electric motors, steam turbines, hydraulic motors, or gas engines. After further research and analysis, our team decided that an electric motor would be the ideal driver selection for our air coolers, as this is commonly used and would be most appropriate for our coolers considering the relatively low amount of brake horsepower required to drive the cooler fans. Electricity would power these motors using the extra capacity from the generator on the facility. We have also verified this selection with Chevron, and other types of drivers for our cooler designs will not be considered. 6.4 MATLAB Results and Sensitivities Using our methodology for detailed design and the MATLAB model, we obtained key parameters to determine power and sizing requirements for each of the compressors, 34

49 scrubbers, and coolers in our VRU design. To run the overall MATLAB VRU program at average conditions, we used the pressures, temperatures, and flow rates listed earlier in the report in Table 3. These base conditions consist of an ambient air temperature of 80 o F at average gas flow rates. From a practical standpoint, certain aspects associated with our design change on a daily basis. To simulate these variations, we used our MATLAB program to run multiple cases with varying parameters to reflect realistic conditions and analyze the effects on key model outputs. Performing this sensitivity analysis allowed us to refine our model and adjust assumptions made based on our design s feasibility in extreme conditions. Two key fluctuations are modeled in our VRU design: ambient air temperatures and gas flow rates. A summary of these sensitivity cases can be seen in Table 7, and these cases will discussed in further detail in the compressor results section of the report. We have considered sensitivity effects solely on the three compressors in our model because altering these conditions only had a significant impact on the compressor output values. The results presented for the scrubber and cooler designs were obtained at average conditions using the values for case 2, or the base case, as seen in Table 7. Table 7. Sensitivity Cases. 35

50 6.4.1 Separator and Cooler Results From the MATLAB output, we populated an Excel spreadsheet for the scrubbers containing the inner separator diameters (D vd ) and seam to seam lengths (L ss ) in feet. These values can be seen in Table 8. Since vendors only make separators with diameters and lengths in 6-inch increments, the dimensions were converted to inches and then rounded up to the next multiple of six inches. The slenderness ratio (L ss / D vd ) for each separator was then calculated based on the rounded dimensions; these values can also be seen in Table 8. Typical slenderness ratios for two-phase separators fall in the range of 3 to 5, and all three of our separators meet these criteria [8]. Table 8. Separator Design Outputs. We obtained the necessary outputs from the model to determine the horsepower and size requirements for our three cooler designs, providing data for the cost analysis and skid model. These values, as seen in Table 10, include the fan driver brake horsepower, total extended surface heat-transfer area of tubes (A x ), tube bundle face area (F a ) which represents the heat-transfer surface available to airflow, and fan blade diameter (D fan ) rounded up to the next available fan size. The total power required to 36

51 drive our entire VRU system was determined using the cooler and compressor brake horsepower values. Table 9. Cooler Design Outputs Compressor Results and Sensitivities To simulate hot and cold day (daytime vs. nighttime) conditions, we used ambient air temperature to model three cases: minimum (cold), average, and maximum (hot) temperatures. After simulating these cases, also referred to as cases 1-3 in Table 7, our results showed that both the outlet temperature and brake horsepower for compressors 2 and 3 increased with ambient temperature, as seen in the compressor outputs for cases 1-3 of Table 10. When compared to our base case conditions, the outlet temperature and brake horsepower changed by an average 11% and 4%, respectively. The outlet temperature is a critical aspect of our design as it determines compression feasibility. For the hot conditions (case 3), we observed that the outlet temperature for compressor 2 was slightly above the critical temperature of 300 o F, illustrating that our design may not be feasible for extremely hot weather without making key changes. To minimize these compressor outlet temperatures for extreme conditions, many future modifications can be made to our design: add more air cooling, use or add water cooling, increase number of 37

52 compression stages, change compressor type, increase compressor efficiency, and/or resize the existing compressors. Surging effects were also considered, as the gas flow rates coming from both stock tanks are constantly fluctuating, especially with the presence of excess liquids or pipeline pressure changes. To model these deviations in flow, the given gas flow rates were used as averages, while ±30% of these values provided the maximum and minimum flow rates; these conditions are indicated as cases 2, 4, and 5 in Table 7. According to our design results, the brake horsepower for all three compressors significantly increased with gas throughput, as seen in Table 10. Compressor power changed by an average 30% when compared to our base case values, which stresses the importance of accounting for extreme conditions in our design. Compressor brake horsepower is a key design output because it not only determines minimum sizing and power requirements for the compressor designs, but also affects compressor selection, equipment cost analysis, VRU skid layout for the platform, and the total power required to run our system. Table 10. Compressor Design Outputs. 38

53 6.5 Bill of Materials Before creating a skid layout of our proposed design, we had to list all components with their dimensions in a Bill of Materials (BOM) as shown in Table 11. Dimensions were determined using product catalogs from vendors, MATLAB models, and calculations described above [14,15]. The BOM was also needed to determine part of the financial costs concerning capital expenses, where costs for the specific components were obtained using values from 2003 [16]. We doubled the cost values to account for the recent increase in raw materials and labor rate costs. The total equipment cost was estimated to be approximately $750,000, which was also used for further financial analysis. The BOM provides a layout of the type and quantity of individual components needed for the VRU system as well as their estimated costs. 39

54 Table 11. Bill of Materials. 6.6 Solid Skid Model The VRU system will need to be placed on a skid, which represents a base platform that will be able to withstand the weight of components placed on top. The VRU components will be placed on a skid, transported, and finally be placed on the production platform offshore. To fit on the production platform, we had to focus on reducing the skid size as much as possible. From the BOM, we were able to lay out a two-dimensional sketch of the VRU on the skid. Figure 14 shows the two-dimensional sketch from the top view. 40

55 29 ft. Key Scrubbers Coolers Compressors Cooler 1 Cooler 2 Cooler 3 12 ft. S1 Com 1&2 S2 Com 3 S3 3 MMSCFD 2 MMSCFD 1 MMSCFD 90 psig 5 psig 45 psig Figure 14. Two Dimensional Skid Layout. Looking at this skid layout above, we can see the overall relative dimensions as well as the streams entering and exiting the VRU. The process starts with the 2MMSCFD flow running first through the two-stage compressor to increase the pressure from 5psig to 15psig, cooler 1, scrubber (S1), and returning to the same two-stage compressor (Com1&2) to be recompressed from 15psig to 45psig. Since the first compressor (Com1&2) is a two-stage compressor, it is able to simultaneously compress two flows at one time. From there, it passes through cooler 2, scrubber (S2), and then enters the second compressor (Com3). The 1 MMSCFD stream is added into the stream to be compressed from 45psig to 90psig in the second compressor (Com3). Finally the combined stream of 3 MMCFD is cooled, separated (S3), and rerouted to the sales compressor. 41

56 The final dimensions for the skid will be 29 ft. long and 12 ft. wide with a maximum height of 10 ft due to scrubber 3 s height. The components are spaced 2 ft. apart from each other and 6 in. from the edges of the skid to allow access for piping and maintenance. Figure 15 is a three-dimensional model of our proposed design following the same layout, from left to right, as the two-dimensional model in Figure 14. As seen in Figure 15, the two stage reciprocating compressor on the left is much larger in comparison to the single stage reciprocating compressor because it will have to recompress two streams. The heat exchangers shown in the back are the largest pieces of equipment in our final design while the vertical scrubbers are the tallest. Figure 15. Three Dimensional Skid Layout. 42

57 7 FINANCIAL ANALYSIS 7.1 Annual Sales Loss Now that we have covered the key aspects of sizing components, we shift our focus to financial costs. Currently the gas stream of 45psi (1 MMSCFD) is being burnt off into the atmosphere, so we calculated the value of the gas that was being lost. To do this, we needed a cost estimate of how much the natural gas is worth in today s market, also known as spot price. Since the spot price of natural gas changes every day, we chose to look at the spot trends over the last year, published on online markets, as well as future price predictions from natural gas price traders and the Energy Information Administration. These prices per million British thermal units (MMBtu) for November 11 th can be seen in Table 12. Table 12. Past and Predicted Natural Gas Spot Prices [17,18,19]. To estimate the value of natural gas being lost in a given day, we took the Henry Hub spot price on the day of November 11, 2009, since this is the closest value to present day, which was $4.18 per million British thermal units [18]. To calculate the sales amount that is lost due to flaring, we had to account for the natural gas heating value which is 1,028 Btu/SCF. Using the equation below we are able to compute the value of the original 1 MMSCFD stream being burnt off: 43

58 Annual Sales Loss = Flowrate (Q)* Heating Value (HV)* Spot Price* Days in a year Annual Sales Loss = 1 MMSCF/day * 1,028 Btu/SCF* $4.18/MMBtu * 365 days/year From our calculations, the annual sales loss from the 1 MMSCFD stream alone is approximately $1,568,400 a year. Instead of earning this profit amount, Chevron is currently burning off the 1 MMSCFD gas stream. 7.2 Investment Costs Capital, installation, and operations and maintenance (O&M) costs are related to the design flow capacity of the stream. We determined the costs for a VRU system for the 3MMSCFD flow capacity leaving the VRU. Due to Chevron s request we were not able to contact vendors for specific prices on equipment; therefore, we derived our financial values from extrapolating capital, installation, and O&M costs available from EPA s Natural Gas Star Program [20]. Capital costs were also compared to values of the specific equipment costs [16]. Table 13 lists the capital, installation, and O&M costs derived. Table 13. VRU Costs [3]. 44

59 Since the above values were obtained in 2004, we doubled the cost estimate to take into account recent increases in labor rates, installation costs, deck differences, cost of raw materials, and equipment costs. Therefore, the cost estimates we focused on for our design were based on the 6000 MSCFD design capacity, rather than the 3000 MSCFD, to have a more conservative and accurate representation of today s prices. Design capacity is the maximum fluid flow the VRU will experience while running. As fluid capacity increases, the investment cost also increases. Capital costs include the cost of the equipment: compressors, separators, and coolers. Installation costs include the cost of a crew to install the system and any extra equipment needed to transport the skid onto the platform. In the above example, installation cost is calculated as 75% of the capital cost [20]. Operation and maintenance costs incorporate the cost of the crew to maintain the VRU, as well as the operating cost to keep the VRU in working order. The investment cost is the sum of the capital and installation cost. As seen in Table 13, the investment cost for our project is approximately $1.3 million. Equipment cost was the major factor in contributing to the investment cost and unavoidable since it relies on the capacity flow. 7.3 Payback and Return on Investment To continue our financial analysis, we calculated the value of recovered gas, the payback period, and the return on investment after the installation of the VRU. The value of recovered gas is the annual value that Chevron may potentially earn by selling off the natural gas recovered by the VRU. The price range of the recovered gas was based on a low and high range from past and future natural gas spot prices from Table 12. To 45

60 calculate the value of recovered gas, we used the same annual sales loss equation as stated previously. Figure 16 graphs the predicted value of recovered gas at 75% runtime versus the natural gas spot price. A 75% runtime was chosen to take into account the annual downtime from maintenance on the VRU equipment [21]. The value of recovered gas for our range of $4.18/MMBtu to $6.50/MMBtu (highlighted in Figure 16) varied from $3.5 million to $5.5 million. In comparison to the initial investment cost of $1.3 million, the profit exceeds the initial cost by double to triple the cost. $25,000,000 Value of Recovered Gas and Net Present Value Dollar Amount $20,000,000 $15,000,000 $10,000,000 $5,000,000 Value of Recovered Gas at 75% NPV 5yrs $0 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 Natural Gas Spot Price Figure 16. Value of Recovered Gas and Net Present Value vs. Natural Gas Spot Price. Now that we know the investment cost and the value of recovered gas, we were able to calculate payback and return on investment. The payback period tells us how long it will take for incoming cash flow to equal the amount invested on implementing 46

61 the VRU system. The payback period was calculated by dividing the initial capital and installation costs by the annual value of the recovered gas. For our low and high range for natural gas spot prices, we calculated payback to be from about 3 months to less than 5 months. This is a considerably short payback and favors the installation of our VRU on the platform. The return on investment differs from the payback period because it determines how much profit is gained in comparison to the initial investment. The return on investment (ROI) was calculated using the equation: ROI = (Value of Recovered Initial Investment)/Initial Investment. For the low and high range spot prices, return on investment varied from 168% to 317%. This is a very high return on investment and if natural gas prices continue to climb, so will Chevron s return on investment. Fast payback and high return on investment makes installing the VRU on the platform a favorable option for Chevron. 7.4 Net Present Value Since Chevron would still like to implement the VRU for environmental reasons even if implementing the VRU on the platform does not add much financial contributions we chose a small discount rate (i) of 10%. The discount rate is the minimum percentage price a company would like to be returned by an investment. By using the 10% discount rate, we calculated the net present value (NPV) of the project for five years. 47

62 To calculate NPV, we used the equation: NPV = AVRG *(PVIFA,n ) CC IC O&MC*(PVIFA i,n ) NPV = Net present value AVRG = Annual value of recovered gas PVIFA = Present value of an annuity n = Number of years i = Discount rate CC = Capital cost O&MC = Operation and maintenance cost The present value of an annuity was obtained from economic tables [22] and based on the discount rate of 10% for a five year span. Again, we took a range considering the changes in natural gas prices. Figure 16 also depicts the linear increase in net present value in relation to the natural gas price. For our low/high range, net present value ranged from $11.3 million to $18.8 million. Since net present value is greater than zero, this project can be deemed a good investment because the company would not be losing any money; in fact, they can still make $11 to $18 million dollars more than the 10% return desired. Almost as important, is the annual revenue Chevron can expect to see after installing the VRU system, also known as annuity. Taking the net present value, we back-calculated to obtain the annual revenue. By knowing the interest rate and the number of years, we determined the annuity of the present value using the conversion factor (1/PVIFA). The equation used the equation: Annuity = Net Present Value * (1/PVIFA). After calculation, for the low and high gas spot prices, the annuity ranged from $3 million to $5 million. After incorporating the VRU system on the platform, Chevron can expect positive annual revenue from the recovered natural gas. 48

63 Considering the short payback, high return on investment, and positive values of net present value and annuity, the financial analysis proves to benefit Chevron financially and would be a great investment if the VRU is implemented. If natural gas prices continue to increase, Chevron will be able to obtain more revenue in the years to come. 8 COST ESTIMATE No costs were associated with our project. A prototype was not required for our project, eliminating material costs. The MATLAB and SolidWorks software we used were available free of charge at the university. Due to resources through the university s libraries, we also did not need to buy technical papers. 9 FUTURE WORK AND RECOMMENDATIONS For future purposes, implementing liquid transfer pumps after each scrubber may be a critical addition to the proposed VRU system to account for surging and the presence of excess liquids in the gas when restarting the VRU. This will help prevent damage to the compressors and decrease downtime when gravity is not sufficient to drain all the liquids to the sump tank. If there is access to a high pressure gas source on the platform, an alternative for vapor recovery could be to use venturi jet ejector technology, which takes a high pressure gas flow and combines it with the low pressure vapors to create an intermediate pressure flow which can then enter the sales compressor or other processing equipment. Currently, venturi jet ejectors have only been implemented onshore, but may 49

64 be used offshore in the future. In addition, venturi jet ejectors have no mechanical moving parts resulting in significantly lower maintenance costs [23]. 10 CONCLUSION In conclusion, our team has developed overall VRU and detailed individual component designs through research and utilization of applicable design tools, along with supporting feasibility calculations and justifications for our selections. A critical component of our engineering analysis included creating a MATLAB computer model to simulate and verify our VRU design, applying principles of thermodynamics, heat transfer, fluid mechanics, and gas separation. A three-dimensional solid model was also created to provide detailed visualization of our VRU design components and overall layout. This VRU system will recover hydrocarbon vapors and re-route the gas to sales on one of Chevron s offshore production platform in the Gulf of Mexico, minimizing gas losses and increasing profits while complying with environmental regulations. Considering the short payback period, high return on investment, and annual revenue of about $4 million associated with the proposed VRU design, our analysis shows this final design solution is financially sound and would be a favorable investment for implementing in the project. We have also provided Chevron with recommendations for future work in terms of further improvement of the final solution and potential investments in new and existing technologies. 50

65 REFERENCES 1. Our Businesses. (n.d.). Retrieved September 3, 2009, from Chevron: 2. Chevron. (2009). Gulf of Mexico Business Unit Fact Sheet. Houston: Chevron North American Exploration and Production. 3. Natural GasSTAR Program. (n.d.). Retrieved September 10, 2009, from 4. Evans, N. (n.d.). Retrieved from 5. Rothenbucher, R. K. (1976). U.S. Patent No. 3,939,906. Washington, DC: U.S. Patent and Trademark Office. 6. Goodyear, M. A. (2002). U.S. Patent No. 6,418,957. Washington, DC: U.S. Patent and Trademark Office. 7. Mokhatab, S., Poe, W., & Speight, J. (2006). Handbook of Natural Gas Transmission and Processing. Burlington: Gulf Publishing 8. Gas Processors Suppliers Association. (1994). Engineering Data Bok. Tulsa: Gas Processors Association. 9. Mohitpour, M., Golshan, H., & Murray, A. (2003). Pipeline Design & Construction: A Practical Approach. New York: American Society of Mechanical Engineers. 10. Hewitt, G. (1998). Heat Exchanger Design Handbook. New York: Begell House Inc. 11. Kroger, D. G. (2004). Air-Cooled Heat Exchangers and Cooling Towers. PennWell Books. 12. Kuppan, T. (2000). Heat Exchanger Design Handbook. New York: Marcel Dekker Publishing. 13. Svrcek, W., & Monnery, W. (1993). Design Two-Phase Separators Within the Right Limits. Chemical Engineering Progress, Ariel Corporation. (n.d.). Ariel JGM, JGP, JGN, JCQ Compressors [Brochure]. Retrieved from 51

66 15. Air-X-Changers. (n.d.). AXC Model H [Brochure]. Retrieved from AXC_ModelH_11-06.pdf 16. Process Equipment Cost Estimates. (2003, October 15). Retrieved from Oilnergy. (n.d.). NYMEX Henry Hub Natural Gas Price. Retrieved November 19, 2009, from Bloomberg. (n.d.). Energy Prices. Retrieved November 11, 2009, from CME Group. (2009, November 19). Natural Gas Henry Hub Futures. Retrieved November 19, 2009, from EPA's Natural Gas STAR Program, Shell, GCEAG, API, & Rice University. (2004, June 8). Installing Vapor Recovery Units to Reduce Methane Losses [PowerPoint slides]. 21. Quincy Compressor. (n.d.). Cost of Ownership: The Definitive Guide [Brochure]. 22. National Council of Examiners for Engineering and Surveying (Ed.). (2008). Fundamentals of Engineering Supplied-Reference Handbook (8th ed.). Author. 23. Goodyear, M. A., Graham, A. L., Stoner, J. B., Boyer, B. B., Zeringue, L. P., & Society of Petroleum Engineers International. (2003, March). Vapor Recovery of Natural Gas Using Non-Mechanical Technology (SPE No ). Society of Petroleum Engineers Inc. 24. Schmidt, P., Baker, D., Ezekoye, O., & Howell, J. (2006). Thermodynamics: An Integrated Learning System. Hoboken: Wiley. 25. Kline, P. E., Fahlgren, C. E., & Kitchen, M. R. (1971). U.S. Patent No. 3,565,164. Washington, DC: U.S. Patent and Trademark Office. 26. Artemov, L. N., & Bakanov, A. F. (1977). U.S. Patent No. 4,002,444. Washington, DC: U.S. Patent and Trademark Office. 27. Longardner, R. L. (1990). U.S. Patent No. 4,936,109. Washington, DC: U.S. Patent and Trademark Office. 28. Raseley, L. J., Collier, S. J., & McCarty, H. G. (1980). U.S. Patent No. 4,214,883. Washington, DC: U.S. Patent and Trademark Office. 52

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69 APPENDIX A: DESIGN FEASIBILITY CALCULATIONS 5 45 psig: Stock Tank 1 Single Stage Gas Compression Figure 6. Single Stage Compression from Tank 1. o Assumptions Steady State Steady Flow No change in KE, PE Adiabatic Isentropic Compression Constant ratio of specific heats (K) K=1.27, evaluated at T1 using specific heat calculator MATLAB function Compressors are reciprocating with adiabatic efficiencies of η c =.83 [31] o 1 st Law of Thermodynamics reduces to: w c,13 = h 3 h 1 o For Isentropic compression the inlet temperature and adiabatic outlet temperature are related by: T 3S = T 1 P 3 P 1 k 1 k 1 + T 1 = R = 390 o F o The actual compressor outlet temperature is found by the following relation: T 3 = T 3S T 1 η c + T 1 = R = o F o Operating temperature T 3 >300 o F, so cooling phase and multiple compression stages are required for 5 45spig pressure increase 5 45 psig: Stock Tank 1 Two Stage Gas Compression with interstage cooling A-1

70 Figure 7. Two Stage Compression from Tank 1. o Set each compression ratio per stage = P 3 P 1 = P 5 P 4 = 3 to evenly distribute compression load o Assumptions: Steady State Steady Flow No change in KE, PE Adiabatic Isentropic Compression Constant K=1.27, evaluated at T1 using specific heat calculator MATLAB function Compressors are reciprocating with adiabatic efficiencies of η c =.83 Pressure change across cooler is negligible T ambient =80 o F o 1 3: Following same isentropic compression analysis as for single stage compression T 3S = T 1 P 3 P 1 k 1 k 1 + T 1 = R = F T 3 = T 3S T 1 η c + T 1 = R = F o 3 4: Cooler rule of thumb For air cooling assume discharge temperature of 25 o F above ambient dry bulb temperature [8] T 4 = T amb + 25 o F = 105 o F A-2

71 o 4 5: Following same isentropic compression analysis as with single stage compression T 5S = T 1 P 5 P 4 k 1 k 1 + T 4 = R = o F T 5 = T 5S T 4 η c + T 4 = R = o F o Since both T 3 and T 5 are safely below 300 o F, 2 stage compression with intercooling will boost the gas pressure without damaging the equipment o Now we will check the feasibility of single stage compression for the combined 45 psig gas flow stream psig: combined Gas flow Stream Figure 8. Combined Gas Flow Compression. o Same assumptions as Stock Tank 1 Single Stage Gas Compression T 8S = T 7 P 8 P 7 k 1 k 1 + T7 = R = o F T 8 = T 8S T 7 η c + T 7 = R = o F o The operating temperature T8<300 o F, so the compression can be achieved in one stage without cooling Based on these feasibility calculations, we must have two compression stages for the 2MMSCFD gas flow from stock tank 1 and only one compression stage for the combined 3MMSCFD gas flow. A-3

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73 APPENDIX B: DETAILED VRU PROCESS FLOW DIAGRAM Figure B-1. Detailed VRU Process Flow Diagram. B-1