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PIPESIM PROJECT_2012

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Optimizing given field study for the term project of Advanced Production Eng.

Optimizing given field study for the term project of Advanced Production Eng.

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  • 1. PE 7023 Fall 2012 Term Design Project Reservoir and ProductionManagement of Hurricane Field Author: Lecturer: Sel¸uk Fidan c Prof.Dr. Holden Zhang December 10, 2012
  • 2. Abstract Brown et al.[1] was stated that many production systems are operatinginefficiently; therefore, most can be improved significantly by careful analy-sis. It is not unusual to find flow lines that are too small and tubing sizes thatare too large or too small. It was almost 30 years ago Dr. Brown was talk-ing about this in his famous book. It is still true in some aspects, howeverdeveloping technologies and new softwares decrease this improper designs.One of the most popular software for this purpose is PIPESIM by Schlum-berger. In our project, PIPESIM is used to apply NODAL analysis underdifferent conditions to see the performance of the production network system. In this project we were asked to optimize the Hurricane field which islocated in Tulsa County. It consists of seven different reservoirs and has 11wells. Four of the wells that PEC-3, PEC5, PEC-6 and PEC-7 are producingwith gas lift and five of them that PEC-1, PEC-2, PEC-4, PEC-8 and PEC-9have choke installed on the top of the well. The objective of this work is tooptimize the field performance applying NODAL analysis, Well performanceand Artificial Lift Performance, changing tubing size and surface choke siz-ing. For the gas lift wells we are able to conduct NODAL analysis, Wellperformance and Artificial Lift Performance and for the wells have produc-ing naturally we are able to apply NODAL analysis on the bottom of the well,on the top of the well and at the separator. We conducted our work mainlyputting the node at the bottom of the well but for the example purpose weconduct one case for PEC-1 putting the node on the wellhead and put thisinto the results section.
  • 3. Contents1 Introduction 112 Procedure 14 2.1 Under Normal Conditions . . . . . . . . . . . . . . . . . . . . 15 2.2 Changing Tubing Diameters . . . . . . . . . . . . . . . . . . . 15 2.3 Changing Choke Bean Size . . . . . . . . . . . . . . . . . . . . 15 2.4 Gas Lift Optimization and Well Performance . . . . . . . . . . 16 2.4.1 Gas Lift Optimization . . . . . . . . . . . . . . . . . . 16 2.4.2 Well Performance . . . . . . . . . . . . . . . . . . . . . 16 2.5 Changing Static Pressure . . . . . . . . . . . . . . . . . . . . . 173 Results 18 3.1 Under Normal Conditions . . . . . . . . . . . . . . . . . . . . 18 3.1.1 Nodal Analysis . . . . . . . . . . . . . . . . . . . . . . 18 3.2 Changing Tubing Diameters . . . . . . . . . . . . . . . . . . . 21 3.3 Changing Choke Bean Size . . . . . . . . . . . . . . . . . . . . 22 3.4 Gas Lift Optimization and Well Performance . . . . . . . . . . 23 3.5 Changing Static Pressure . . . . . . . . . . . . . . . . . . . . . 25 3.6 Possible improvements for the wells . . . . . . . . . . . . . . . 25 3.7 Putting Nodal Point on Wellhead . . . . . . . . . . . . . . . . 264 Conclusions 29 Bibliography 30A Reservoir and Production Management of Hurricane Field 31 A.1 Well Information . . . . . . . . . . . . . . . . . . . . . . . . . 32 A.1.1 PEC-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 2
  • 4. A.1.2 PEC-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 A.1.3 PEC-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 A.1.4 PEC-4 . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 A.1.5 PEC-5, PEC-6 and PEC-7 . . . . . . . . . . . . . . . . 33 A.1.6 PEC-8 and PEC-9 . . . . . . . . . . . . . . . . . . . . 33 A.1.7 PEC-10 . . . . . . . . . . . . . . . . . . . . . . . . . . 34 A.1.8 PEC-11 . . . . . . . . . . . . . . . . . . . . . . . . . . 34B Figures 35C Tables 142D Matlab Code 146 D.1 Post processing code for changing tubing diameters . . . . . . 146 3
  • 5. List of Figures 1.1 Complete Producing simple system. [1] . . . . . . . . . . . . . 12 1.2 Pressure losses in complete system. [1] . . . . . . . . . . . . . 12 3.1 Analysing PEC-1 from Nodal Analysis figure. . . . . . . . . . 20 3.2 Tubing diameter (inches) vs. Flow rate sbbl/d. . . . . . . . . . 21 3.3 Schematic view of Well PEC-1, simulation after PIPESIM. . . 27 3.4 IPR and OPR curve with different flowline diameters for PEC-1. 27 3.5 IPR and OPR curve with different tubing and flowline diam- eters for PEC-1. . . . . . . . . . . . . . . . . . . . . . . . . . . 28 B.1 Actual Gathering System from the project file. . . . . . . . . . 36 B.2 Actual Gathering System after PIPESIM. . . . . . . . . . . . 37 B.3 Flowline for B1. . . . . . . . . . . . . . . . . . . . . . . . . . . 38 B.4 Flowline for B2. . . . . . . . . . . . . . . . . . . . . . . . . . . 38 B.5 Flowline for B3. . . . . . . . . . . . . . . . . . . . . . . . . . . 38 B.6 Flowline for B4. . . . . . . . . . . . . . . . . . . . . . . . . . . 39 B.7 Flowline for B5. . . . . . . . . . . . . . . . . . . . . . . . . . . 39 B.8 Flowline for B6. . . . . . . . . . . . . . . . . . . . . . . . . . . 39 B.9 Schematic view of well PEC-1 from project file. . . . . . . . . 40 B.10 Schematic view of Well PEC-1, simulation after PIPESIM. . . 40 B.11 Production History for PEC-1 from project file. . . . . . . . . 41 B.12 IPR and OPR for PEC-1 under normal conditions. . . . . . . 42 B.13 Pressure vs. depth for PEC-1 under normal conditions. . . . . 43 B.14 Temperature vs. depth for PEC-1 under normal conditions. . . 43 B.15 IPR and OPR for PEC-1 with changing tubing diameters. . . 44 B.16 Pressure vs. depth for PEC-1 with changing tubing diameters. 45 B.17 Temperature vs. depth curve for PEC-1 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 B.18 IPR and OPR for PEC-1 with changing choke bean size. . . . 46 4
  • 6. B.19 Pressure vs. depth for PEC-1 with changing choke bean size. . 47B.20 Temperature vs. depth curve for PEC-1 with changing choke bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47B.21 Nodal Analysis curves for PEC-1 with changing static pressures. 48B.22 Schematic view of well PEC-2 from project file. . . . . . . . . 49B.23 Schematic view of Well PEC-2, simulation after PIPESIM. . . 49B.24 Schematic view of Topographical Survey for PEC-2. . . . . . . 50B.25 IPR and OPR for PEC-2 under normal conditions. . . . . . . 51B.26 Pressure vs. depth for PEC-2 under normal conditions. . . . . 52B.27 Temperature vs. depth for PEC-2 under normal conditions. . . 52B.28 IPR and OPR for PEC-2 with changing tubing diameters. . . 53B.29 Pressure vs. depth for PEC-2 with changing tubing diameters. 54B.30 Temperature vs. depth curve for PEC-2 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54B.31 IPR and OPR for PEC-2 with changing choke bean size. . . . 55B.32 Pressure vs. depth for PEC-2 with changing choke bean size. . 56B.33 Temperature vs. depth curve for PEC-2 with changing choke bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56B.34 Nodal Analysis curves for PEC-2 with changing static pressures. 57B.35 Schematic view of well PEC-3 from project file. . . . . . . . . 58B.36 Schematic view of Well PEC-3, simulation after PIPESIM. . . 58B.37 IPR and OPR for PEC-3 under normal conditions. . . . . . . 59B.38 Pressure vs. depth for PEC-3 under normal conditions. . . . . 60B.39 Temperature vs. depth for PEC-3 under normal conditions. . . 60B.40 IPR and OPR for PEC-3 with changing tubing diameters. . . 61B.41 Pressure vs. depth for PEC-3 with changing tubing diameters. 62B.42 Temperature vs. depth curve for PEC-3 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62B.43 IPR and OPR for PEC-3 at different static pressures. . . . . . 63B.44 IPR and OPR for for PEC-3 at different static pressures and gas lift at 2918 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 64B.45 IPR and OPR for for PEC-3 at different static pressures and gas lift at 8811 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 64B.46 Well Performance curves under normal conditions. . . . . . . . 65B.47 Well Performance curves when gas lift at 2918 ft. . . . . . . . 66B.48 Well Performance curves when gas lift at 8811 ft. . . . . . . . 66B.49 Artificial lift performance curves under normal conditions. . . 67B.50 Artificial lift performance curves when gas lift at 2918 ft. . . . 68 5
  • 7. B.51 Artificial lift performance curves when gas lift at 8811 ft. . . . 68B.52 Nodal Analysis curves for PEC-3 with changing static pressures. 69B.53 Schematic view of well PEC-4 from project file. . . . . . . . . 70B.54 Schematic view of Well PEC-4, simulation after PIPESIM. . . 70B.55 IPR and OPR for PEC-4 under normal conditions. . . . . . . 71B.56 Pressure vs. depth for PEC-4 under normal conditions. . . . . 72B.57 Temperature vs. depth for PEC-4 under normal conditions. . . 72B.58 IPR and OPR for PEC-4 with changing tubing diameters. . . 73B.59 Pressure vs. depth for PEC-4 with changing tubing diameters. 74B.60 Temperature vs. depth curve for PEC-4 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74B.61 IPR and OPR for PEC-4 with changing choke bean size. . . . 75B.62 Pressure vs. depth for PEC-4 with changing choke bean size. . 76B.63 Temperature vs. depth curve for PEC-4 with changing choke bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76B.64 Nodal Analysis curves for PEC-4 with changing static pressures. 77B.65 Schematic view of well PEC-5 from project file. . . . . . . . . 78B.66 Schematic view of Well PEC-5, simulation after PIPESIM. . . 78B.67 IPR and OPR curves for PEC-5 under normal conditions. . . . 79B.68 Pressure vs. depth curve for PEC-5 under normal conditions. . 80B.69 Temperature vs. depth curve for PEC-5 under normal condi- tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80B.70 IPR and OPR for PEC-5 with changing tubing diameters. . . 81B.71 Pressure vs. depth for PEC-5 with changing tubing diameters. 82B.72 Temperature vs. depth curve for PEC-5 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82B.73 IPR and OPR for PEC-5 at different tubing diameters. . . . . 83B.74 IPR and OPR for for PEC-5 at different tubing diameters and gas lift at 1500 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 84B.75 IPR and OPR for for PEC-5 at different tubing diameters and gas lift at 3000 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 84B.76 Well Performance curves for PEC-5 under normal conditions. . 85B.77 Well Performance curves for PEC-5 when gas lift at 1500 ft. . 86B.78 Well Performance curves for PEC-5 when gas lift at 3000 ft. . 86B.79 Artificial lift performance curves for PEC-5 under normal con- ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87B.80 Artificial lift performance curves for PEC-5 when gas lift at 1500 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 6
  • 8. B.81 Artificial lift performance curves for PEC-5 when gas lift at 3000 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88B.82 Nodal Analysis curves for PEC-5 with changing static pressures. 89B.83 Schematic view of well PEC-6 from project file. . . . . . . . . 90B.84 Schematic view of Well PEC-6, simulation after PIPESIM. . . 90B.85 IPR and OPR curves for PEC-6 under normal conditions. . . . 91B.86 Pressure vs. depth curve for PEC-6 under normal conditions. . 92B.87 Temperature vs. depth curve for PEC-6 under normal condi- tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92B.88 IPR and OPR for PEC-6 with changing tubing diameters. . . 93B.89 Pressure vs. depth for PEC-6 with changing tubing diameters. 94B.90 Temperature vs. depth curve for PEC-6 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94B.91 IPR and OPR for PEC-6 at different tubing diameters. . . . . 95B.92 IPR and OPR for for PEC-6 at different tubing diameters and gas lift at 1550 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 96B.93 IPR and OPR for for PEC-6 at different tubing diameters and gas lift at 3050 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 96B.94 Well Performance curves for PEC-6 under normal conditions. . 97B.95 Well Performance curves for PEC-6 when gas lift at 1550 ft. . 98B.96 Well Performance curves for PEC-6 when gas lift at 3050 ft. . 98B.97 Artificial lift performance curves for PEC-6 under normal con- ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99B.98 Artificial lift performance curves for PEC-6 when gas lift at 1550 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100B.99 Artificial lift performance curves for PEC-6 when gas lift at 3050 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100B.100Nodal Analysis curves for PEC-6 with changing static pressures.101B.101Schematic view of well PEC-7 from project file. . . . . . . . . 102B.102Schematic view of Well PEC-7, simulation after PIPESIM. . . 102B.103IPR and OPR curves for PEC-7 under normal conditions. . . . 103B.104Pressure vs. depth curve for PEC-7 under normal conditions. . 104B.105Temperature vs. depth curve for PEC-7 under normal condi- tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104B.106IPR and OPR for PEC-7 with changing tubing diameters. . . 105B.107Pressure vs. depth for PEC-7 with changing tubing diameters. 106B.108Temperature vs. depth curve for PEC-7 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106 7
  • 9. B.109IPR and OPR for PEC-7 at different tubing diameters. . . . . 107B.110IPR and OPR for for PEC-7 at different tubing diameters and gas lift at 1540 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 108B.111IPR and OPR for for PEC-7 at different tubing diameters and gas lift at 3050 ft. . . . . . . . . . . . . . . . . . . . . . . . . . 108B.112Well Performance curves for PEC-7 under normal conditions. . 109B.113Well Performance curves for PEC-7 when gas lift at 1540 ft. . 110B.114Well Performance curves for PEC-7 when gas lift at 3050 ft. . 110B.115Artificial lift performance curves for PEC-7 under normal con- ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111B.116Artificial lift performance curves for PEC-7 when gas lift at 1540 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112B.117Artificial lift performance curves for PEC-7 when gas lift at 3050 ft. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112B.118Nodal Analysis curves for PEC-7 with changing static pressures.113B.119Schematic view of well PEC-8 from project file. . . . . . . . . 114B.120Schematic view of Well PEC-8, simulation after PIPESIM. . . 114B.121IPR and OPR curves for PEC-8 under normal conditions. . . . 115B.122Pressure vs. depth curve for PEC-6 under normal conditions. . 116B.123Temperature vs. depth curve for PEC-8 under normal condi- tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116B.124IPR and OPR for PEC-8 with changing tubing diameters. . . 117B.125Pressure vs. depth for PEC-8 with changing tubing diameters. 118B.126Temperature vs. depth curve for PEC-8 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118B.127IPR and OPR for PEC-8 with changing choke bean size. . . . 119B.128Pressure vs. depth for PEC-8 with changing choke bean size. . 120B.129Temperature vs. depth curve for PEC-8 with changing choke bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120B.130Nodal Analysis curves for PEC-8 with changing static pressures.121B.131Schematic view of well PEC-9 from project file. . . . . . . . . 122B.132Schematic view of Well PEC-9, simulation after PIPESIM. . . 122B.133IPR and OPR curves for PEC-9 under normal conditions. . . . 123B.134Pressure vs. depth curve for PEC-9 under normal conditions. . 124B.135Temperature vs. depth curve for PEC-9 under normal condi- tions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124B.136IPR and OPR for PEC-9 with changing tubing diameters. . . 125B.137Pressure vs. depth for PEC-9 with changing tubing diameters. 126 8
  • 10. B.138Temperature vs. depth curve for PEC-9 with changing tubing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126B.139IPR and OPR for PEC-9 with changing choke bean size. . . . 127B.140Pressure vs. depth for PEC-9 with changing choke bean size. . 128B.141Temperature vs. depth curve for PEC-9 with changing choke bean size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128B.142Nodal Analysis curves for PEC-9 with changing static pressures.129B.143Schematic view of well PEC-10 from project file. . . . . . . . . 130B.144Schematic view of Well PEC-10, simulation after PIPESIM. . 130B.145IPR and OPR curves for PEC-10 under normal conditions. . . 131B.146Pressure vs. depth curve for PEC-10 under normal conditions. 132B.147Temperature vs. depth curve for PEC-10 under normal con- ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132B.148IPR and OPR for PEC-10 with changing tubing diameters. . . 133B.149Pressure vs. depth for PEC-10 with changing tubing diameters.134B.150Temperature vs. depth curve for PEC-10 with changing tub- ing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . 134B.151Nodal Analysis with Changing Static pressure and tubing di- ameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135B.152Nodal Analysis with Changing Outlet pressure. . . . . . . . . 135B.153Schematic view of well PEC-11 from project file. . . . . . . . . 136B.154Schematic view of Well PEC-11, simulation after PIPESIM. . 136B.155IPR and OPR curves for PEC-11 under normal conditions. . . 137B.156Pressure vs. depth curve for PEC-11 under normal conditions. 138B.157Temperature vs. depth curve for PEC-11 under normal con- ditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138B.158IPR and OPR for PEC-11 with changing tubing diameters. . . 139B.159Pressure vs. depth for PEC-11 with changing tubing diameters.140B.160Temperature vs. depth curve for PEC-11 with changing tub- ing diameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . 140B.161Nodal Analysis with Changing Static pressure and tubing di- ameters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141B.162Nodal Analysis with Changing Outlet pressure. . . . . . . . . 141 9
  • 11. List of Tables C.1 Well- manifold information for Hurricane field. . . . . . . . . . 143 C.2 The manifolds, the processing center and flow line conditions. 143 C.3 Different diameters Nominal and ID values from user guide. . 144 C.4 Flow rate comparison for given data set and at Nodal Analysis point. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144 C.5 Actual Conditions for 11 wells in Hurricane field. . . . . . . . 145 10
  • 12. Chapter 1IntroductionWhat does Nodal Systems Analysis mean? Based on the Brown et al.[1] itis a procedure for determining that flow rate at which an oil or gas well willproduce and then for evaluating the effect of various components, such asthe tubing-string size, flow-line size, separator pressure, choke sites, safetyvalves, downhole restrictions, and well completion techniques including gravelpacks and standard perforated wells. These components are then combinedto optimize the entire system to obtain the most efficient objective flow rate.Each component evaluated separately; then the entire system is combined tooptimize the system effectively. In PIPESIM, Nodal(or system) analysis isdefined as solving the total producing system by placing nodes at the reser-voir sand-face, the well tubing, the flowline and the separator. A node is classified as functional when a pressure differential exists acrossit. In nodal analysis, the producing system is divided into two halves at thesolution node. The solution node is defined as the location where the pres-sure differential upstream (inflow) and downstream (outflow) of the node iszero. This is represented graphically as the intersection points of the inflowand outflow performance curves. Solution nodes can be judiciously selectedto show the effect of certain variables such as inflow performance, perfora-tion density, tubing IDs, flowline IDs and separator pressures. The solutionnode can be placed between any two objects, that is bottom hole (betweencompletion and tubing), and wellhead (between tubing and choke) and soon. 11
  • 13. Figure 1.1: Complete Producing simple system. [1] Figure 1.2: Pressure losses in complete system. [1] In Figure 1.1, and Figure 1.2 show that above explanation schemati-cally. In this work, we try to optimize the Hurrican field based on the infor-mation is provided and tabulated on Table C.5 the reservoir, fluids, well 12
  • 14. and pipeline actual conditions. For detailed describtion please check theAppendix A. 13
  • 15. Chapter 2ProcedureIn this chapter, we will describe the procedure that has been followed for thissection. PIPESIM case studies [2] helped us to build aour model to assigndefault values for each and different part of this work. Before that I wouldlike to mention that for each case building wells are followed putting theinformation from Table C.5 into the PIPESIM. If there was no informationdefault values were used from the PIPESIM user guide. Besides this forhaving GREEN reservoirs give us another unknown of the well informationsuch Temperature of the reservoir and it is assumed that 130 o F . Afterputting fluid, reservoir, boundary and limitations informations for productionfor each single cases in this work we also followed case studies whether wemissed or put wrongly the input parameters just for verifying purposes. First of all, we need to build the network system. After constructing thenetwork system, NODAL analysis is applied without considering sensitivityanalysis to see how system looks like. Having understanding of the systemgives an idea of which part of the well should be considered. First thing isconsiderd to change tubing sizes for Outflow performance curve (OPR) orTubing performance curve (TPC). For example, wells have artificial lift areconsidered to apply Well Performance and Artificial Lift Performance, andwells have chokes that are considered to changing the choke Bean size. Forthis reason, one example is going to give for each of the optimized sectionand rest of it is going to be referred in to the Appendix B for figures andAppendix C for tables. 14
  • 16. 2.1 Under Normal ConditionsThe procedure for running PIPESIM under Normal conditions as follows; • Build network model without modification using PIPESIM. • Run Nodal analysis and get results and save them to check whether we can produce or not. • Obtain pressure and temperature profiles. • Put the results into the Appendix B each well has following orders as Nodal Anlaysis, Pressure and Temperature profiles for normal condi- tons. This is diagnostic place after that different optimization applied to different part of the system to enhance the production system.2.2 Changing Tubing DiametersThe procedure for running PIPESIM Changing Tubing Diameters as follows; • Choose tubing ID Table C.3 based on the PIPESIM User guide pg. 536. • Keep everything constant from normal conditions except for the outflow sensitivity part tubing diameters. • Obtain IPR and OPR and pressure and temperature profiles. • Put the results into the Appendix B after the results are obtained from previous section. • Obtain diameter vs. rate plot for each case and put them into the result section.2.3 Changing Choke Bean SizeThe procedure for running PIPESIM Changing Choke Bean Size as follows; • Choose wells that have choke installed in this work we have PEC-1, PEC-2, PEC-4, PEC-8 and PEC-9. 15
  • 17. • Keep everything constant from normal conditions except for the outflow sensitivity part tubing diameters. • Obtain IPR and OPR and pressure and temperature profiles. • Put the results into the Appendix B after the results are obtained from previous section. • Obtain IPR and OPR and pressure and temperature profiles. • Put the results into the Appendix B after the results are obtained from previous section for specific wells.2.4 Gas Lift Optimization and Well Perfor- mance2.4.1 Gas Lift OptimizationIn this section I followed the similar case study (Gas Lift Optimization) fromPIPESIM case studies and procedure for Gas Lift Optimization as follows; • Choose wells that have gas lift in this work we have PEC-3, PEC-5, PEC-6 and PEC-7. • From the classwork and coursework material [3] we learned that when we have the gas lift we should play with the gas lift position. And Prof. Zhang mentioned in the class putting gas lift at the deeper point we have in the system in order to get more effective results for most of the cases. Therefore, I tried three different cases, first I run the system without changing any placement and get the results for Artificial Lift Performance. And repeated the work placing the gas lift on top point and closing the other valves, and continue to only open the deepest point gas lift and closing the all other valves.2.4.2 Well PerformanceIn this section I followed the similar case stud (Gas Lift Design) from PIPESIMcase studies and procedure for Well Performance for gas lift as follows; 16
  • 18. • Choose wells that have gas lift installed in this work we have PEC-3, PEC-5, PEC-6 and PEC-7. • Similar procedure for gas lift optimization is followed with changing gas lift deoth and figures are obtained and put into the Appendix B with order.2.5 Changing Static PressureIn this section procedure for Changing Static Pressure as follows; • Changing tubing diameters and static pressure curves were obtained using Nodal Analysis. This is important for PEC-10 and PEC-11. • Results put into the order for each cases into the Appendix B. 17
  • 19. Chapter 3ResultsIn this section of the report we present the results for each case and referthe figures for each wells from Appendix B. We put all the figures into theAppendix B, in the first part of the figures we try to represent each wellas possible as we can based on the figures in the Design project. For thisreason I put first original figure then simulated ones. Actual conditions canbe seen from figures B.1 and B.2 and then for the flow line part I put thesix different flowline that we have in this network system in figures B.3,B.4, B.5, B.6, B.7 and B.8.3.1 Under Normal ConditionsIn this chapter we will explain the each of the wells from Nodal Analysis toGas lift performance mainly putting the node bottom of the well and giveone example for the putting the node on the wellhead. After applying pro-cedures from Chapter 2, we have an idea about the wells diagnostics. Nextproceeding sections are all about the diagnostics and finding the solutions.3.1.1 Nodal AnalysisUnder normal conditions IPR and OPR curves were obtained and put intothe Appendix B for figures. In Table C.4, it is clearly seen that onlyseveral wells field data is matching with the simulation results for flow ratecomparison. For the gas lift injection wells we have problems because simula-tion results and actual data are way off values from each other. For PEC-1 18
  • 20. we get good IPR and OPR curve in figure B.12 shows that initial reservoirpressure good enough to produce from the well. Because Pi is bigger thanPo . And Productivity index is low because of the angle θ is high. Changingtubing sizes will improve the performance. When we look at the PEC-2 fromthe simulation in figure B.25, angle θ is small so the productivity index ishigh so we can increase the tubing diameters, however in field data it sayswe do not produce from PEC-2 and it is usually under shut in condition. Ithas GREEN reservoir next to it and they have same manifold to the processcenter. For PEC-3 in figure B.37, is the one of the gas lift well and in NAit shows there is no operating points. And IPR and OPR curve has strangebehavior. For PEC-4 in figure B.55, Pi is smaller than Po , production isnot possible under this conditions. Looking at the PEC-5 in figure B.67and PEC-6 in figure B.85 IPR and OPR has no intersection and operatingpoints. We can not produce from this wells. For PEC-7 in figure B.103,OPR has high pressure ant zero production rate which means we have toincrease reservoir pressure in order to produce, but still gas lift wells undernormal condition no way to produce. For PEC-8 in figure B.121, it hassimilar behavior with PEC-2 angle θ is small so the productivity index ishigh so we can increase the tubing diameters. PEC-9 in figure B.133 showsgood IPR and OPR behavior. PEC-10 in figure B.145 and PEC-11 infigure B.155 have similar problem initially Po is bigger than Pi , so thiscondition also need to be optimized. 19
  • 21. 20 Figure 3.1: Analysing PEC-1 from Nodal Analysis figure.
  • 22. 3.2 Changing Tubing DiametersIn this section using PIPESIM guide, we choose several tubing diametersfrom Table C.3 and applied the change into the outflow sensitivity. Resultsare tabulated after each section results in orderly, can be found at AppendixB. IPR and OPR curves can be found for different tubing diameters for PEC-1 in figure B.15, PEC-2 in figure B.28, PEC-3 in figure B.40, PEC-4in figure B.58, PEC-5 in figure B.73, PEC-6 in figure B.88, PEC-7 infigure B.106, PEC-8 in figure B.124, PEC-9 in figure B.136, PEC-10 infigure B.148 and PEC-11 in figure B.158. Figure 3.2: Tubing diameter (inches) vs. Flow rate sbbl/d. In Figure 3.2, we can see that almost every well shown in the figure ex-cept PEC-5 due to the no operating points available on IPR and OPR curve.Based on the course materials we say that when the tubing diameter vs. flowrate relationship shows that after increasing diameters flow rate reaches max-imum value and with increasing diameter flow rate becomes smaller(indicates 21
  • 23. that unstable region). Gas wells (PEC-3, PEC-6 and PEC-7) do not havestable points, wells that show stable behaviors are PEC-1, PEC-2, PEC-8and PEC-9.3.3 Changing Choke Bean SizeIn this section we examined the effect of the changing Choke Bean Size andput the results as in order in to the Appendix B. Using choke gives system arestriction. It can be modeled as a fixed-size orifice, in which form it presentsa restriction to flow resulting in a pressure drop that increases as flow rateincreases. In our field we have five wells which PEC-1, PEC-2 , PEC-4, PEC-8 and PEC-9 have choke installed with different sizes. When wechange the choke size we increase the production rate and decrease the OPRPo . This gives us to find the optimum bean size for the wells. For PEC-1changing choke sizes gives till 1.25 inches of choke bean after that all thevalues are goes to the same values. More difference between 0.5 and 0.75inches as it can be seen from figure B.18. For PEC-2 in figure B.31biggest difference can be seen between choke size 0.5 to 0.75 inches. PEC-4in figure B.61 when the bean size goes to 0.75, we can see that Po becomessmaller than Pi , so we can produce from this well when we change the chokesize. For the PEC-8 in figure B.127, although it seems when the choke sizeincrease we have better OPR curve, but for choke size 0.5 inches we have theclosest production rate 2933 BBPD for the real one is 2900 BBPD. Thereforechoosing choke bean as 0.5 inches instead of 1.0 inches gives close to the fieldcase. For PEC-9 in figure B.139, choosing choke size between 0.25 and 0.5gives the optimum value for production rate for this well. 22
  • 24. 3.4 Gas Lift Optimization and Well Perfor- manceIn this section of project we present both Gas Lift Optimization and GasLift Well Performance putting the valve and injecting the gas at differentdepth. In this case we have 4 wells that are PEC-3,PEC-5,PEC-6 andPEC-7. Each of them certain amount of valves installed at different places.Each wells figures first one shows result for Well Performance curves andsecond figure shows that Artificial Lift Performance curve. First we getresults for without changing conditons for PEC-3 in figure B.46, in thisfigure it is shown that with increasing gas injection rate, stock tank liquidrate is increasing till 1 MMSCFD after that higher the injection rate goeslower stock tank liquid flowrate at outlet. When we look at the figure B.49with increasing water cut have reverse effect on stock tank liquid flow rateat outlet, higher the water cut lower the stock tank flow rate at outlet withincreasing gas injection. For PEC-5, in figure B.76 and figure B.79,interestingly enough at normal conditions there is no information available.For PEC-6, in figure B.94 it has some trend in terms of increasing gasinjection rate and system outlet pressure and at outlet we can say that allthe curves almost converges the same values on stock tank liquid flowrateat outlet except the case injection rate is 1 and 1.2 MMSCFPD, and figureB.97 with increasing water cut has stock tank liquid level increment, inaddition to this with discontinued values for watercut is 20 % and 30 %. InPEC-7, figure B.112, gas injection rate smaller than 0.6 MMSCFPD doesnot have any impact on the stock tank liquid flowrate at outlet. Moreover,gas injection rate greater than 1.2 have tendency to converge on the similarvalues at outlet stock tank flow rate, means that no need to inject more than1.2 MMSCFPD. In figure B.115, shows that increasing water cut valueshave some good trend on the stock tank flowrate at outlet when the gasinjection rate is more than 1.2 MMSCFPD. Secondly without having anyexpense of the changing valves just tried to get one valve which is for thiscase top one leave open and get the results for PEC-3 in figure B.47, curveshave good trend except injection gas rate smaller than 1 MMSCFPD, it givesan idea that injecting gas on the shortest part does not have much impacton stock tank flow rate at outlet. For the artificial lift performance curvein figure B.50 does not show good trend for the performance. For PEC-5figure B.77 this well performace curve shows good trend for gas injection 23
  • 25. rate greater than 1.2 MMSCFPD and all the curves converge to the similarstock tank liquid flow rate at outlet. In figure B.80, have stock tank liquidrate maximum 8 SBBPD and increasing water cut does not have any effect onstock tank liquid flow rate at outlet . For PEC-6, figure B.95, seems havegood trend but it is not stable, flow rate is 11 STBPD for the maximumgas injection rate. In figure B.98, increasing water cut value till 60 %does not have any effect on outlet stock tank flow rate except 70%, it givesmaximum flow rate at outlet when the gas injection rate 0.8 MMSCFPD,after that it is decreasing. For PEC-7 figure B.113, has interesting trendinjection gas flow rate smaller than 2 MMSCFPD does not give productionon the surface. In figure B.116 has discontinued for the increasing watercut values have reverse effect on the stock tank flow rate on surface. Lastly,I got the results for putting the gas injection into the deepest valve openingdepth and got the results shown in each case. For PEC-3, in figure B.48,for well performance at the deepest point gives very good trend and withincreasing gas injection rate stock tank outlet flow rate is increasing whichis the indication of the chooseing the deepest point gives reasonable matchwith the flow rate for actual conditions.In figure B.51, with increasing watercut, stock tank liquid flow rate is decreasing and at the same time there isnice continuous trend with incresing gas injection rate. This is also anotherindication of choosing the right or close to right point. For PEC-5, in figureB.78, we get the almost the same flow rate for the actual conditons whenwe use injection gas rate between 0.6-0.8 MMSCFPD. With figure B.81,increasing water cut gives increase at the outlet flow rate with increasing gasinjection rate. For PEC-6, figure B.96, well performance curves for bothPEC-5 and PEC-6 have similar trend and similar injection rate range 0.6-0.8MMSCFPD, the reason is this because both of them producing at the samereservoir and most of the properties they have the same. In figure B.99, it isobvious that both PEC-5 and PEC-6 have the similar trend in performanceof artificial lift. For PEC-7, in figure B.114, shows again similar trendfrom previous two cases, for the PEC-7 actual flow rate is 280 BBPD inorder to get this we should increase the injection rate to 0.6 MMSCFPD andonly inject gas at the deepest point we have on teh system. In figure B.117,from the artificial lift performance curves, PEC-7 shows similar trends thatPEC-5 and PEC-6 showed. 24
  • 26. 3.5 Changing Static PressureIn this part we increased the static pressure to get several IPR curves and tryto enhance PEC-10 and PEC-11. For PEC-10, in figure B.151, whenwe increase the static pressure to minimum 3800 psi, we have productionotherwise Pi is smaller than Po and there is no production and at the sametime increasing tubing diameters to 3.548 gives optimum point. Changingonly tubing diameters did not work for this case. In figure B.152, I changedthe outlet pressure from 300 to 70 psi and got the operating point and biggerPi than Po . For PEC-11 figure B.161, with increasing static pressure weovercome Pi smaller than Po , and able to produce, at the same time increasingtubing diameter to 4 inches going to give us optimum IPR and OPR curves,but it is going to cost a lot because the depth of the well is 12000 ft. In thisfigure B.162, changing outlet pressure gives liquid loading problem, so theonly way to produce from this well is increase static pressure and increasethe tubing diameter.3.6 Possible improvements for the wells 1. For PEC-1, it seems there is no need to be improvement. Actual pro- duction rate and simulated one almost same values. And Pi is greater than Po we are able to produce from the well. 2. For PEC-2, although given information shows that this well does not produce, however in simulation it gives production rate. It may because having GREEN field gives confusion to the program. 3. For PEC-3, PEC-5,PEC-6 and PEC-7 are the gas lift wells and after conducting both Well Performance and Artificial Lift Performance show that injecting gas at the deepest point is going to give better results. And also we saw that increasing gas injection rate does not necessarily be the right thing after some point. 4. For PEC-4, this is one of the well has choke installed. After diagnostic, increasing choke bean size minimum to 0.75 inches gives Po smaller than Pi , so we are able to produce from this well. 5. For PEC-8, adjust the choke size to the 0.5 inches going to provide optimum flow rate with the actual data. 25
  • 27. 6. For PEC-9, adjusting choke sizes between 0.25 and 0.5 gives optimum flow rate with actual data. 7. For PEC-10, and PEC-11 as mentioned in the generic document, they have very similar wells and after conducting changing static pressure for this wells and increasing tubing size are going to give improvement for those two wells. However, it is going to be expensive operationa and it has to be considered in economical way.3.7 Putting Nodal Point on WellheadThis section is special place in terms of putting the NODAL Analysis point ontop of the well and get the IPR and OPR with changing flowline diametersand tubing diameters. This is just an example how the system looks likewhen we have NODAL point on top of the well for PEC-1 figure 3.3. Itis clear thatfrom figure 3.4 changing flowline diameter has impact on theOPR curve, but after 4 inches curves are overlapping on themself and notmuch effect seen that is the indication of 4 inches is the optimum point forflow line diameters. 26
  • 28. Figure 3.3: Schematic view of Well PEC-1, simulation after PIPESIM.Figure 3.4: IPR and OPR curve with different flowline diameters for PEC-1. 27
  • 29. 28 Figure 3.5: IPR and OPR curve with different tubing and flowline diameters for PEC-1.
  • 30. Chapter 4Conclusions 1. Hurricane field network system is built successfully, and for each well is diagnosted for different conditions. Suc as, under normal conditions, changing tubing size, changing chkesize, applying gas lift design and op- timization to get well performance and artificial lift performace for gas lift wells and lastly static pressure change applied in order to optimize the whole system. 2. In the chapter two, procedures are described and chapter thre explained the results and give suggestion for the possible improvement for the wells. 3. We found that although we have data from the field does not necessearily match the simulated data. But still simulation gives some idea and pos- sible improvement without trying and error. 4. Almost all the cases I run for this project I put the node at the bottom of the well and did the analysis. For one case I put the NODAL ANAL- YSIS point on to the top and got IPR and OPR curve with changing flowline and tubing diameters. 29
  • 31. Bibliography[1] K. E. Brown. The Technology of Artificial Lift Methods. PennWell Books, first edition, 1984.[2] Schlumberger. PIPESIM Version 2011.1 User’s Guide.[3] Holden Zhang. Modeling and Optimization of Oil and Gas Production Systems. PE 7023 FALL 2012 Advanced Production Design Course Notes, 2012. 30
  • 32. Appendix AReservoir and ProductionManagement of Hurricane FieldIn the appendix A, all the information is based on the project descriptionfrom Prof. Holden Zhang’s Generic Project document1 . The Hurricane fieldis located in Tulsa County. It consists of seven different reservoirs. Thereare 11 existing wells. The objective of this project is to optimize the fieldperformance. Currently, the field is totally producing 7915 STB/D oil from all the wellsbut Well PEC-5. All of the wells connected to a central processing centerin figure B.142. The production of another field called Green Field, 21681STB/D of oil and 44 MMSCF/D natural gas, is transported to the sameprocessing center. The reservoirs in Hurricane fields have different characteristics. Thewell depth varies between 3000 ft and 12500 ft. Formations are sandstone,dolomites, limestone with varying porosities and permeabilities. Four of thewells are on artificial lift while six of them produce naturally and one well isshut in. The production of the wells is sent to different manifolds based ontheir geographic location in figure B.1 and after PIPESIM B.2. 1 Generic Project Design is well planned and aimed to teach how to use PIPESIM anduse the course materials effectively in order to accomplish this work. 31
  • 33. A.1 Well InformationA.1.1 PEC-1This well was completed in 1986 at an interval of 12467-12523 ft. in a forma-tion composed by dolomites from medium Cretaceous of the reservoir SEC-1.The static pressure has been kept around 3900 psi due to the water injection.The flowing pressure and oil production started to decline at the end of 1994and the well started to produce water. From 1995 to 1998, the flowing pres-sure and oil production have declines notable, and the water cut increased.This behavior is shown in figure figure B.9 and after PIPESIM figure B.10. The additional information on production history: At the beginning of1987, the production was increased from 993 STB/D to 2327 STB/D throughstimulation indicating that formation was originally damaged. The produc-tion was held constant until April 1991 when it was increased by changingthe choke settings. In 1995, the oil production started to decline and wellstarted to cut water with salinity of 65,000 ppm. According to laboratorytests, the salinity of the formation water is 150,000 ppm, which indicates thatthe injection water is present in the well. Increase in the water saturationaround the near wellbore may result in additional damage. The most of theinformation of this well is given in Table C.5.A.1.2 PEC-2This well was completed in 1997 at an interval of 6371-6476 ft. (figureB.22 and figure B.23) in a formation composed by dolomites from mediumCretaceous of the reservoir SITEC. This is the only well in the reservoir. Thegeneral characteristics of the system rock-fluids are given in the Table C.5.The topography of the flow line from PEC-2 to P2 is given in figure B.24.This well is shut in most of time.A.1.3 PEC-3This well produces from a sand stone reservoir which has static pressure of3400 psi, 12 % of porosity and 40 md of permeability. It was completed with2 7/8 in. tubing and 8 conventional gas lift valves (figure B.35 and figureB.36). These valves cannot be changed unless the tubing is replaced since 32
  • 34. they are part of the tubing. There has been a severe communication betweengas-lift valves. The communication was detected at 4091 ft (third valve). The well has 6890 ft of 3 in. flow line and has reported a productivityindex of 3 bbls/psi. The general characteristics of the system rock-fluids aregiven in Table C.5.A.1.4 PEC-4This well has two pay zones from sandstone reservoir; one was abandonedbecause of high water cut, and the other has been producing at a rate of 420STB/D with 15 % water. The reservoir has a static pressure of 2198 psi, 15% porosity and 44 md of permeability. The well was completed with a 3 1/2in. tubing (See figure B.53 and figure B.54). Water coning is expectedto be a problem. Therefore, the well is choked with a choke of 0.5 in. toprevent the well from watering out. The general characteristics of the systemare given in Table C.5.A.1.5 PEC-5, PEC-6 and PEC-7These wells are producing from reservoir called VSU, which is a consolidatedsandstone, with a pressure of 600 psi at 3750 ft and a temperature of 140◦ F.The sand has been producing for more than 20 years, leaving 15,398,438 bblof oil in place. The general characteristics of the system are given in TableC.5. These wells are gas lifted and their characteristics, physical parametersand the completions are given in Table C.5. For PEC-5, in figure B.65and figure B.66. For PEC-6, in figure B.83 and figure B.84 and forPEC-7, in figure B.101 and figure B.102.A.1.6 PEC-8 and PEC-9These wells are producing from reservoir called CAR, which is a highly frac-tures with a high permeability of 500 md. The general characteristics of thesystem are given in Table C.5. The schematics of these wells are given inFor PEC-8, in figure B.119 and figure B.120 and for PEC-9, in figureB.131 and figure B.132. The pressure loss through perforations is reportedto be 1,415 psi. The perforation shot density is reported as 4 shots per feet. 33
  • 35. A.1.7 PEC-10This well is producing from a reservoir called SJ-1. This sand has a thicknessof 30 ft with 30 % of porosity and 30 md of permeability. The actual staticpressure of the reservoir is 2,800 psi and the bubble pressure of the oil is3,500 psi. The general characteristics of the system are given in Table C.5.The schematic of the well is given in figure B.143 and figure B.144.A.1.8 PEC-11This well is producing from a reservoir called SJ-1. This sand has a thicknessof 30 ft with 30 % of porosity and 30 md of permeability. The actual staticpressure of the reservoir is 2,800 psi and the bubble pressure of the oil is3,500 psi. The general characteristics of the system are given in Table C.5.The schematic of the well is given in figure B.153 and figure B.154. Thiswell is very similar to PEC-10. The difference is that this well is susceptibleto water coning. Therefore, the maximum flow rate should be 800 bbl/d. 34
  • 36. Appendix BFiguresAppendix B gives and extensive information about the application that hasbeen done in terms of figures. All the figures are well organized and showedhere starting from Normal Conditions, Changing tubing diameters, Changingchoke Bean size, Applying artificial lift performance and well performanceand ended up changing static pressure values. 35
  • 37. 36 Figure B.1: Actual Gathering System from the project file.
  • 38. 37 Figure B.2: Actual Gathering System after PIPESIM.
  • 39. Figure B.3: Flowline for B1.Figure B.4: Flowline for B2.Figure B.5: Flowline for B3. 38
  • 40. Figure B.6: Flowline for B4.Figure B.7: Flowline for B5.Figure B.8: Flowline for B6. 39
  • 41. Figure B.9: Schematic view of well PEC-1 from project file.Figure B.10: Schematic view of Well PEC-1, simulation after PIPESIM. 40
  • 42. Figure B.11: Production History for PEC-1 from project file. 41
  • 43. 42 Figure B.12: IPR and OPR for PEC-1 under normal conditions.
  • 44. Figure B.13: Pressure vs. depth for PEC-1 under normal conditions.Figure B.14: Temperature vs. depth for PEC-1 under normal conditions. 43
  • 45. 44 Figure B.15: IPR and OPR for PEC-1 with changing tubing diameters.
  • 46. Figure B.16: Pressure vs. depth for PEC-1 with changing tubing diameters.Figure B.17: Temperature vs. depth curve for PEC-1 with changing tubingdiameters. 45
  • 47. 46 Figure B.18: IPR and OPR for PEC-1 with changing choke bean size.
  • 48. Figure B.19: Pressure vs. depth for PEC-1 with changing choke bean size.Figure B.20: Temperature vs. depth curve for PEC-1 with changing chokebean size. 47
  • 49. 48 Figure B.21: Nodal Analysis curves for PEC-1 with changing static pressures.
  • 50. Figure B.22: Schematic view of well PEC-2 from project file.Figure B.23: Schematic view of Well PEC-2, simulation after PIPESIM. 49
  • 51. Figure B.24: Schematic view of Topographical Survey for PEC-2. 50
  • 52. 51 Figure B.25: IPR and OPR for PEC-2 under normal conditions.
  • 53. Figure B.26: Pressure vs. depth for PEC-2 under normal conditions.Figure B.27: Temperature vs. depth for PEC-2 under normal conditions. 52
  • 54. 53 Figure B.28: IPR and OPR for PEC-2 with changing tubing diameters.
  • 55. Figure B.29: Pressure vs. depth for PEC-2 with changing tubing diameters.Figure B.30: Temperature vs. depth curve for PEC-2 with changing tubingdiameters. 54
  • 56. 55 Figure B.31: IPR and OPR for PEC-2 with changing choke bean size.
  • 57. Figure B.32: Pressure vs. depth for PEC-2 with changing choke bean size.Figure B.33: Temperature vs. depth curve for PEC-2 with changing chokebean size. 56
  • 58. 57 Figure B.34: Nodal Analysis curves for PEC-2 with changing static pressures.
  • 59. Figure B.35: Schematic view of well PEC-3 from project file.Figure B.36: Schematic view of Well PEC-3, simulation after PIPESIM. 58
  • 60. 59 Figure B.37: IPR and OPR for PEC-3 under normal conditions.
  • 61. Figure B.38: Pressure vs. depth for PEC-3 under normal conditions.Figure B.39: Temperature vs. depth for PEC-3 under normal conditions. 60
  • 62. 61 Figure B.40: IPR and OPR for PEC-3 with changing tubing diameters.
  • 63. Figure B.41: Pressure vs. depth for PEC-3 with changing tubing diameters.Figure B.42: Temperature vs. depth curve for PEC-3 with changing tubingdiameters. 62
  • 64. 63 Figure B.43: IPR and OPR for PEC-3 at different static pressures.
  • 65. Figure B.44: IPR and OPR for for PEC-3 at different static pressures andgas lift at 2918 ft.Figure B.45: IPR and OPR for for PEC-3 at different static pressures andgas lift at 8811 ft. 64
  • 66. 65 Figure B.46: Well Performance curves under normal conditions.
  • 67. Figure B.47: Well Performance curves when gas lift at 2918 ft.Figure B.48: Well Performance curves when gas lift at 8811 ft. 66
  • 68. 67 Figure B.49: Artificial lift performance curves under normal conditions.
  • 69. Figure B.50: Artificial lift performance curves when gas lift at 2918 ft.Figure B.51: Artificial lift performance curves when gas lift at 8811 ft. 68
  • 70. 69 Figure B.52: Nodal Analysis curves for PEC-3 with changing static pressures.
  • 71. Figure B.53: Schematic view of well PEC-4 from project file.Figure B.54: Schematic view of Well PEC-4, simulation after PIPESIM. 70
  • 72. 71 Figure B.55: IPR and OPR for PEC-4 under normal conditions.
  • 73. Figure B.56: Pressure vs. depth for PEC-4 under normal conditions.Figure B.57: Temperature vs. depth for PEC-4 under normal conditions. 72
  • 74. 73 Figure B.58: IPR and OPR for PEC-4 with changing tubing diameters.
  • 75. Figure B.59: Pressure vs. depth for PEC-4 with changing tubing diameters.Figure B.60: Temperature vs. depth curve for PEC-4 with changing tubingdiameters. 74
  • 76. 75 Figure B.61: IPR and OPR for PEC-4 with changing choke bean size.
  • 77. Figure B.62: Pressure vs. depth for PEC-4 with changing choke bean size.Figure B.63: Temperature vs. depth curve for PEC-4 with changing chokebean size. 76
  • 78. 77 Figure B.64: Nodal Analysis curves for PEC-4 with changing static pressures.
  • 79. Figure B.65: Schematic view of well PEC-5 from project file.Figure B.66: Schematic view of Well PEC-5, simulation after PIPESIM. 78
  • 80. 79 Figure B.67: IPR and OPR curves for PEC-5 under normal conditions.
  • 81. Figure B.68: Pressure vs. depth curve for PEC-5 under normal conditions.Figure B.69: Temperature vs. depth curve for PEC-5 under normal condi-tions. 80
  • 82. 81 Figure B.70: IPR and OPR for PEC-5 with changing tubing diameters.
  • 83. Figure B.71: Pressure vs. depth for PEC-5 with changing tubing diameters.Figure B.72: Temperature vs. depth curve for PEC-5 with changing tubingdiameters. 82
  • 84. 83 Figure B.73: IPR and OPR for PEC-5 at different tubing diameters.
  • 85. Figure B.74: IPR and OPR for for PEC-5 at different tubing diameters andgas lift at 1500 ft.Figure B.75: IPR and OPR for for PEC-5 at different tubing diameters andgas lift at 3000 ft. 84
  • 86. 85 Figure B.76: Well Performance curves for PEC-5 under normal conditions.
  • 87. Figure B.77: Well Performance curves for PEC-5 when gas lift at 1500 ft.Figure B.78: Well Performance curves for PEC-5 when gas lift at 3000 ft. 86
  • 88. 87 Figure B.79: Artificial lift performance curves for PEC-5 under normal conditions.
  • 89. Figure B.80: Artificial lift performance curves for PEC-5 when gas lift at1500 ft.Figure B.81: Artificial lift performance curves for PEC-5 when gas lift at3000 ft. 88
  • 90. 89 Figure B.82: Nodal Analysis curves for PEC-5 with changing static pressures.
  • 91. Figure B.83: Schematic view of well PEC-6 from project file.Figure B.84: Schematic view of Well PEC-6, simulation after PIPESIM. 90
  • 92. 91 Figure B.85: IPR and OPR curves for PEC-6 under normal conditions.
  • 93. Figure B.86: Pressure vs. depth curve for PEC-6 under normal conditions.Figure B.87: Temperature vs. depth curve for PEC-6 under normal condi-tions. 92
  • 94. 93 Figure B.88: IPR and OPR for PEC-6 with changing tubing diameters.
  • 95. Figure B.89: Pressure vs. depth for PEC-6 with changing tubing diameters.Figure B.90: Temperature vs. depth curve for PEC-6 with changing tubingdiameters. 94
  • 96. 95 Figure B.91: IPR and OPR for PEC-6 at different tubing diameters.
  • 97. Figure B.92: IPR and OPR for for PEC-6 at different tubing diameters andgas lift at 1550 ft.Figure B.93: IPR and OPR for for PEC-6 at different tubing diameters andgas lift at 3050 ft. 96
  • 98. 97 Figure B.94: Well Performance curves for PEC-6 under normal conditions.
  • 99. Figure B.95: Well Performance curves for PEC-6 when gas lift at 1550 ft.Figure B.96: Well Performance curves for PEC-6 when gas lift at 3050 ft. 98
  • 100. 99 Figure B.97: Artificial lift performance curves for PEC-6 under normal conditions.
  • 101. Figure B.98: Artificial lift performance curves for PEC-6 when gas lift at1550 ft.Figure B.99: Artificial lift performance curves for PEC-6 when gas lift at3050 ft. 100
  • 102. 101 Figure B.100: Nodal Analysis curves for PEC-6 with changing static pressures.
  • 103. Figure B.101: Schematic view of well PEC-7 from project file.Figure B.102: Schematic view of Well PEC-7, simulation after PIPESIM. 102
  • 104. 103 Figure B.103: IPR and OPR curves for PEC-7 under normal conditions.
  • 105. Figure B.104: Pressure vs. depth curve for PEC-7 under normal conditions.Figure B.105: Temperature vs. depth curve for PEC-7 under normal condi-tions. 104
  • 106. 105 Figure B.106: IPR and OPR for PEC-7 with changing tubing diameters.
  • 107. Figure B.107: Pressure vs. depth for PEC-7 with changing tubing diameters.Figure B.108: Temperature vs. depth curve for PEC-7 with changing tubingdiameters. 106
  • 108. 107 Figure B.109: IPR and OPR for PEC-7 at different tubing diameters.
  • 109. Figure B.110: IPR and OPR for for PEC-7 at different tubing diameters andgas lift at 1540 ft.Figure B.111: IPR and OPR for for PEC-7 at different tubing diameters andgas lift at 3050 ft. 108
  • 110. 109 Figure B.112: Well Performance curves for PEC-7 under normal conditions.
  • 111. Figure B.113: Well Performance curves for PEC-7 when gas lift at 1540 ft.Figure B.114: Well Performance curves for PEC-7 when gas lift at 3050 ft. 110
  • 112. 111 Figure B.115: Artificial lift performance curves for PEC-7 under normal conditions.
  • 113. Figure B.116: Artificial lift performance curves for PEC-7 when gas lift at1540 ft.Figure B.117: Artificial lift performance curves for PEC-7 when gas lift at3050 ft. 112
  • 114. 113 Figure B.118: Nodal Analysis curves for PEC-7 with changing static pressures.
  • 115. Figure B.119: Schematic view of well PEC-8 from project file.Figure B.120: Schematic view of Well PEC-8, simulation after PIPESIM. 114
  • 116. 115 Figure B.121: IPR and OPR curves for PEC-8 under normal conditions.
  • 117. Figure B.122: Pressure vs. depth curve for PEC-6 under normal conditions.Figure B.123: Temperature vs. depth curve for PEC-8 under normal condi-tions. 116
  • 118. 117 Figure B.124: IPR and OPR for PEC-8 with changing tubing diameters.
  • 119. Figure B.125: Pressure vs. depth for PEC-8 with changing tubing diameters.Figure B.126: Temperature vs. depth curve for PEC-8 with changing tubingdiameters. 118
  • 120. 119 Figure B.127: IPR and OPR for PEC-8 with changing choke bean size.
  • 121. Figure B.128: Pressure vs. depth for PEC-8 with changing choke bean size.Figure B.129: Temperature vs. depth curve for PEC-8 with changing chokebean size. 120
  • 122. 121 Figure B.130: Nodal Analysis curves for PEC-8 with changing static pressures.
  • 123. Figure B.131: Schematic view of well PEC-9 from project file.Figure B.132: Schematic view of Well PEC-9, simulation after PIPESIM. 122
  • 124. 123 Figure B.133: IPR and OPR curves for PEC-9 under normal conditions.
  • 125. Figure B.134: Pressure vs. depth curve for PEC-9 under normal conditions.Figure B.135: Temperature vs. depth curve for PEC-9 under normal condi-tions. 124
  • 126. 125 Figure B.136: IPR and OPR for PEC-9 with changing tubing diameters.
  • 127. Figure B.137: Pressure vs. depth for PEC-9 with changing tubing diameters.Figure B.138: Temperature vs. depth curve for PEC-9 with changing tubingdiameters. 126
  • 128. 127 Figure B.139: IPR and OPR for PEC-9 with changing choke bean size.
  • 129. Figure B.140: Pressure vs. depth for PEC-9 with changing choke bean size.Figure B.141: Temperature vs. depth curve for PEC-9 with changing chokebean size. 128
  • 130. 129 Figure B.142: Nodal Analysis curves for PEC-9 with changing static pressures.
  • 131. Figure B.143: Schematic view of well PEC-10 from project file.Figure B.144: Schematic view of Well PEC-10, simulation after PIPESIM. 130
  • 132. 131 Figure B.145: IPR and OPR curves for PEC-10 under normal conditions.
  • 133. Figure B.146: Pressure vs. depth curve for PEC-10 under normal conditions.Figure B.147: Temperature vs. depth curve for PEC-10 under normal con-ditions. 132
  • 134. 133 Figure B.148: IPR and OPR for PEC-10 with changing tubing diameters.
  • 135. Figure B.149: Pressure vs. depth for PEC-10 with changing tubing diame-ters.Figure B.150: Temperature vs. depth curve for PEC-10 with changing tubingdiameters. 134
  • 136. Figure B.151: Nodal Analysis with Changing Static pressure and tubingdiameters. Figure B.152: Nodal Analysis with Changing Outlet pressure. 135
  • 137. Figure B.153: Schematic view of well PEC-11 from project file.Figure B.154: Schematic view of Well PEC-11, simulation after PIPESIM. 136
  • 138. 137 Figure B.155: IPR and OPR curves for PEC-11 under normal conditions.
  • 139. Figure B.156: Pressure vs. depth curve for PEC-11 under normal conditions.Figure B.157: Temperature vs. depth curve for PEC-11 under normal con-ditions. 138
  • 140. 139 Figure B.158: IPR and OPR for PEC-11 with changing tubing diameters.
  • 141. Figure B.159: Pressure vs. depth for PEC-11 with changing tubing diame-ters.Figure B.160: Temperature vs. depth curve for PEC-11 with changing tubingdiameters. 140
  • 142. Figure B.161: Nodal Analysis with Changing Static pressure and tubingdiameters. Figure B.162: Nodal Analysis with Changing Outlet pressure. 141
  • 143. Appendix CTables 142
  • 144. The following table C.1 gives the well-manifold information.Table C.1 Well- manifold information for Hurricane field. W ell Condition Manifold Destination PEC-3 Gas Lift P1 P2 PEC-5 Gas Lift P1 P2 PEC-6 Gas Lift P1 P2 PEC-7 Gas Lift P1 P2 PEC-1 Natural Flow P4 P2 PEC-4 Natural Flow P4 P2 PEC-8 Natural Flow P4 P2 PEC-9 Natural Flow P4 P2 PEC-10 Natural Flow P3 P2 PEC-11 Natural Flow P3 P2 PEC-2 Natural Flow P5 P2 The manifolds, the processing center and flow line conditions are givenin the following table C.2.Table C.2 The manifolds, the processing center and flow line conditions. M − P1 M − P 3 M − P 4 M − P 5 PC Pressure (psi) 70 300 70 667 60 Oil Flow Rate (STB/D) 1160 1363 5392 21681 29596 Water Flow Rate (STB/D) 175 269 291 0 735 Gas Flow Rate (MMSCF/D) 0.51 5.92 6.13 43.36 55.92 Length (ft) 3300 1000 1300 40000 Diameter (in.) 8 10 12 15 API 30 143
  • 145. Table C.3 Different diameters Nominal and ID values from user guide. Nominal Bore ID in 238 2.041 7 28 2.259 312 2.75 4.0 3.548 1 42 4.0 5.0 4.276 5.0 4.560 6.0 5.24 7.0 5.75 7.0 6.276Table C.4 Flow rate comparison for given data set and at Nodal Analysispoint. Wells After Nodal Analysis, BBPD Given actual Conditions, BBPD PEC-1 1259.2171 1136 PEC-2 3232.7249 0 PEC-3 0 712 PEC-4 690.9286 420 PEC-5 1.4592 156 PEC-6 1.4666 180 PEC-7 1.4707 280 PEC-8 9568.8 2900 PEC-9 9825.716 1260 PEC-10 709.8362 780 PEC-11 880.636 1000 144
  • 146. Table C.5 Actual Conditions for 11 wells in Hurricane field. PEC-1 PEC-2 PEC-3 PEC-4 PEC-5 PEC-6 PEC-7 PEC-8 PEC-9 PEC-10 PEC-11 RESERVOIR SEC-1 SITEC NS620 RG194 VSU VSU VSU CAR CAR SJ-1 SJ-1 Model Type PSS Fetkovich. Vogel Vogel Vogel Vogel Vogel PSS PSS Vogel Vogel Static Pressure [psi] 3982 3982 3400 2198 600 650 650 4000 4000 2800 2800 Reservoir Temp. [F] 284 128.3 278 298 140 140 140 180 180 298 298 Permeability [mD] 40 460 40 44 15 15 15 500 500 30 30 Porosity [%] 4 4.9 12 15 30 30 30 8 8 30 30 Rock Dolomite Dolomite Sand Sand CS CS CS Limestone Limestone Sand Sand Drainage radius [ft] 300 - - - - - - 1600 1600 - - Wellbore diameter [ft] 6.5 6.5 - - - - - 9 9 - - Pay thickness [ft] 56 79 15 30 350 350 350 120 60 30 30 Skin factor 40 0 0 7 0 0 0 0 0 0 0 Total Recovery factor [%] 30 35 30 32 40 20 40 35 35 35 35 Actual Recovery factor [%] 1 30 20 15 20 20 20 15 15 28 28 Oil in place [bbl] 10,568,000 365,500,000 37,568,000 35,000,000 30,796,875 30,796,875 30,796,875 50,010,000 50,010,000 14,563,804 14,563,804 Bubble Pressure [psi] 3210 3210 3600 3821 1250 1250 1250 4000 4000 3500 3500 FLUIDS Fluid Model Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Black Oil Oil gravity [API] 35 30.5 25 38.2 26 26 26 30 30 25 25 Gas gravity [rel.to air] 0.861 0.793 0.7 0.7 0.7 0.7 0.7 0.65 0.65 0.65 0.65 Water gravity [rel.to water] 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 1.02 GOR [ft3/bbl] 1500 440 400 4214 444 474 500 800 800 4706 4000 Water cut [%] 23 10 20 15 10 5 0 0 0 15 30 WELL145 Production method NF NF GL NF GL GL GL NF NF NF NF Gas lift flow rate [MMSCFD] - - 0.5 - 0.4 0.4 0.4 - - - - Vertical flow correlation HB BB Ansari HB MB MB MB Ansari Ansari HB HB Inclination Angle [deg] 0 0 0 0 0 0 0 26 0 0 0 Depth of Perforation [ft] 12495 6424 12132.5 10428 3750 3802 3810 9000 9400 12110 12165 Pwf [psi] 1830 3258 3200 2066 486 500 560 2435 2350 2081 1840 Pwh [psi] 300 1095 260 1095 80 80 80 500 430 670 1000 Production Rate [BBPD] 1136 0 712 420 156 180 280 2900 1260 780 1000 Open Flow Potential 22474 - - 500 450 1200 - - Choke [inch] 0.875 0.5 - 0.5 0 0 0 1 1 - - PIPELINE Horizontal Flow Correlation BBR D,A,F BBR Xiao Xiao Xiao Xiao Xiao Xiao BBR BBR Length [ft] 8202 17585 6890 4921 3000 3000 3200 5000 4501 9950 11000 Diameter [inc.] 4 10 3 3 4 4 4 6 6 3 6 Inclination [deg] 0 0 0 0 0 0 0 0 0 0 0
  • 147. Appendix DMatlab CodeD.1 Post processing code for changing tubing diameters% Post P r o c e s s i n g f o r P r o d u c t i o n Design P r o j e c t %% S e l c u k Fidanclc ; clear a l l ; close a l l ;% Steam q u a l i t y %DataFromWells = x l s r e a d ( ’ TubingSize . x l s x ’ ) ; % pascal% Pec−1subplot ( 2 , 5 , 1 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 1 ) , ’ b− ’ , . . .’ linewidth ’ ,3);ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−1 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , . . . ’ F o n t S i z e ’ , 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on 146
  • 148. % Pec−2subplot ( 2 , 5 , 2 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 3 ) , . . . ’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−2 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on% Pec−3subplot ( 2 , 5 , 3 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 4 ) , . . . ’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−3 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on% Pec−4subplot ( 2 , 5 , 4 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 5 ) , . . . ’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−4 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 147
  • 149. 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on% Pec−6subplot ( 2 , 5 , 5 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 6 ) , . . . ’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−6 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on% Pec−7subplot ( 2 , 5 , 6 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 7 ) , . . . ’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−7 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on% Pec−8subplot ( 2 , 5 , 7 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 8 ) , . . . 148
  • 150. ’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−8 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on% Pec−9subplot ( 2 , 5 , 8 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 9 ) , . . . ’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−9 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on% Pec−10subplot ( 2 , 5 , 9 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 1 0 ) , ’ b− ’ , . . . ’ linewidth ’ ,3);ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , ’ C a l i b r i ’ , . . . ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , ’ C a l i b r i ’ , . . . ’ FontSize ’ , 18)legend ( ’PEC−10 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . 149
  • 151. ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on% Pec−11subplot ( 2 , 5 , 1 0 )plot ( DataFromWells ( : , 2 ) , DataFromWells ( : , 1 1 ) , . . . ’ b− ’ , ’ l i n e w i d t h ’ , 3 ) ;ylabel ( ’Q, Flow r a t e , s b b l /d ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)xlabel ( ’ Tubing d i a m e t e r ( i n c h e s ) ’ , ’ Fontname ’ , . . . ’ C a l i b r i ’ , ’ FontSize ’ , 18)legend ( ’PEC−11 ’ , ’ Fontname ’ , ’ C a l i b r i ’ , ’ F o n t S i z e ’ , . . . 1 4 , ’ L o c a t i o n ’ , ’ SouthEast ’ )set ( gca , ’ XAxisLocation ’ , ’ top ’ )set ( gca , ’ FontSize ’ , 1 2 , . . . ’ XMinorTick ’ , ’ on ’ , . . . ’ YMinorTick ’ , ’ on ’ , . . . ’ Tic kDi r ’ , ’ out ’ ) ;box ( ’ on ’ ) ;grid on 150