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# Gas Economic-1.pptx

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# Gas Economic-1.pptx

Gas economic

Gas economic

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### Gas Economic-1.pptx

1. 1. Gas economics Dr. Khaled Saeed Ba-Jaalah Petroleum Economics- PET 511 Level-5 Semester-9 ‫حضرمـــوت‬ ‫جــــامعة‬ HADRAMOUT UNIVERSITY ‫البترولية‬ ‫الهندسة‬ ‫قسم‬ DEPARTMENT OF PETROLEUM ENGINEERING ‫البترول‬ ‫و‬ ‫الهندسـة‬ ‫كليـة‬ FACULTY OF ENGINEERING & PETROLEUM 29/11/2022
2. 2. Introduction Economics yardsticks is applied the same as before; i.e. in crude oil economics. Determine gas compositions thru gas chromatography. The higher the heavier components the higher the value of natural gas. Table (3-1) shows the typical composition for both associated gas and non- associated gas. 2
3. 3. 3 Associated Gas Non-Associated gas Component 0.0168 0.0131 N2 0.0562 0.0411 CO2 0.0328 0.042 H2S 0.3073 0.59 C1 0.2254 0.11 C2 0.2147 0.088 C3 0.0537 0.052 i-C4
4. 4. 0.0536 0.05 n-C4 0.0159 0.007 i-C5 0.0159 0 n-C5 0.0066 0.005 C6 0.0011 0.0018 C7+ 4
5. 5. Introduction :(cont.) 5 Sale price is determined using Gross Heating Values utilizing the British Thermal Units (BTU). Table (3-2) gives the BTU values for the different composition of natural gas.
6. 6. 6 Cross Heating Values (BTU/SCF) Component Cross Heating Values (BTU/SCF) Component 3253 n-C4 0 N2 4010 i-C5 0 CO2 4000 n-C5 637 H2S 4756 C6 1010 C1 5503 C7 1769 C2 6250 C8 2517 C3 6997 C9 3262 i-C4
7. 7. Introduction :(cont.) 7 Example (3-1): Determine the Gross Heating Values (BTU/SCF) for the gas composition given in Table (3-1)? Solution: 1-For associated gas:
8. 8. 8 GHV (BTU/SCF) GHV (BTU/SCF) from Table (3-2) Composition Component 0 0 0.0168 N2 0 0 0.0562 CO2 20.8936 637 0.0328 H2S 310.373 1010 0.3073 C1 398.7326 1769 0.2254 C2 540.3999 2517 0.2147 C3 175.1694 3262 0.0537 i-C4 174.3608 3253 0.0536 n-C
9. 9. 63.759 4010 0.0159 i-C5 63.6 4000 0.0159 n-C5 31.3896 4756 0.0066 C6 6.0533 5503 0.0011 C7+ 1784.7312 1.000 Total 9
10. 10. Introduction :(cont.) 10 2- For non-associated gas: GHV (BTU/SCF) GHV (BTU/SCF) from Table (3-2) Composition Component 0 0 0.0131 N2 0 0 0.0411 CO2 26.754 637 0.042 H2S 595.9 1010 0.59 C1 194.59 1769 0.11 C2 221.496 2517 0.088 C3
11. 11. 169.624 3262 0.052 i-C4 162.65 3253 0.05 n-C4 28.07 4010 0.007 i-C5 0 4000 0 n-C5 23.78 4756 0.005 C6 9.9054 5503 0.0018 C7+ 1432.7694 1.000 Total 11
12. 12. Costs and Revenues 12 1. Costs: In order to produce the petroleum there are two main types of costs: 1. Fiscal costs which include bonuses, royalties and taxes. 2. Field costs which can be classified into four elements:
13. 13. Costs and Revenues A. Exploration costs B. Development costs C. Operating costs D. Abandonment costs 13
14. 14. Costs and Revenues Exploration and development costs together are termed CAPEX, while the operating cost is called OPEX. The abandonment cost is considered to be a special category of cost because it is associated with environmental safety and does not produce any future profit for the company. 14
15. 15. Costs and Revenues 15 It is also a very large cost component, and could be equal to or more than the development cost. The allocation of field cost (CAPEX, OPEX) into elements differs from company to company, due to the variable nature of petroleum projects (e.g. different reservoir types) and the fiscal regime applied in the project (e.g. some host governments determine the cost which will be capitalized and the cost which will be depleted).
16. 16. Capital Cost (CAPEX) 16 Usually, it is paid only once at the beginning of the project, although sometimes CAPEX occurs during the economic life of the project; for example, if the project applies new techniques and facilities in order to increase petroleum production. It is divided into 3years: 1. 20% at the first year 2. 50% at the second year 3. 30% at the third year
17. 17. Capital Cost (CAPEX) According to the purpose of the cost, the CAPEX can be broken down into two main categories: 1-Exploration cost: The exploration cost contains the costs of geological and geophysical studies which are made by the company itself or purchased from other parties like service companies. 17
18. 18. Capital Cost (CAPEX) 18  In addition, exploration wells are drilled and their cost is considered as exploration costs.  If the exploration effort is unsuccessful, then the cost is called sunk cost.  Usually the sunk cost does not appear directly in the project future cash flow evaluation, but it affects the actual financial situation of the project.
19. 19. Capital Cost (CAPEX) 19 2-Development cost: The development cost consists of three main cost elements: 1. Development well drilling cost 2. Production installation cost 3. Cost of facilities required for petroleum transportation.
20. 20. Capital Cost (CAPEX) The development methods and techniques differ from project to project depending on various factors, such as onshore/offshore, technologies available, rock type, the size of the oil or gas fields, etc. 20
21. 21. Operating Cost (OPEX) 21 The operating cost (OPEX) represents the cost of operating and maintaining the petroleum project. It is occurred periodically. Operating cost may be classified on to: 1. Feedstock 2. Utilities 3. Maintenance of facilities 4. Overheads
22. 22. Operating Cost (OPEX) 5. Production costs which includes:  Treatment Costs  Workover  Secondary recovery costs  Water disposal costs 6. Evacuation costs 7. Insurance costs 22
23. 23. Abandonment cost 23 Abandonment cost is the cost paid for cleaning up the wells and facilities, and the restoration of the production site after production ends. This cost is incurred at the end of project life; in some regimes the abandonment payment is allowed to be funded in advance through deductions from annual profits (abandonment provision or contribution).
24. 24. Abandonment cost The abandonment cost covers the cost of wellhead removal in addition to removal of the production and petroleum transport equipment, plugging of the well and treatment and restoration of the production area. 24
25. 25. Revenue 25 Revenue arises from petroleum production sales (oil, gas or condensate) in addition to other activities such as money received from asset sales or interest on the provisions(abandonment, depreciation and others).
26. 26. Revenue In order to calculate the revenue from petroleum sales, the prices should be predicted. For each project the price forecasts should be chosen depending on the expertise of the economist. 26
27. 27. Example 27 CAPEX 5,000,000,000 \$ OPEX 3.0% ofCAPEX Reserves 10,000,000 MMSCF Production 2000 MMSCFD Sales Price 2.00 \$/mmbtu Hurdle Rate 15.0% Decline Start 60% Oforiginalreserves Decline % 5% Composition Mole% N2 0.20 H2S 0.10 CO2 0.05 C1 0.50 C2 0.10 C3 0.05 C4 0.00
28. 28. Solution:- 28 R/P 13.70 Years Platue 8.22 Years Composition Mole% HeatingValue,btu/SCF GHV N2 0.20 0 0 H2S 0.10 637 64 CO2 0.05 0 0 C1 0.50 1010 505 C2 0.10 1769 177 C3 0.05 2517 126 C4 0.00 3262 0 Cum= 871.45 BTU/SCF
29. 29. Solution:(cont.) 29 2. Year ProductionRate,MMSFD Volume,MMSCF/yr Cum.MMSCF CAPEX,\$ OPEX, \$ MM btu/yr GrossRevnue(\$) 1 \$1,000,000,000 \$0 2 \$2,500,000,000 \$0 3 \$1,500,000,000 \$0 4 2000 730,000 730,000 \$150,000,000 636,158,500 \$1,272,317,000 5 2000 730,000 1,460,000 \$150,000,000 636,158,500 \$1,272,317,000 6 2000 730,000 2,190,000 \$150,000,000 636,158,500 \$1,272,317,000 7 2000 730,000 2,920,000 \$150,000,000 636,158,500 \$1,272,317,000 8 2000 730,000 3,650,000 \$150,000,000 636,158,500 \$1,272,317,000 9 2000 730,000 4,380,000 \$150,000,000 636,158,500 \$1,272,317,000 10 2000 730,000 5,110,000 \$150,000,000 636,158,500 \$1,272,317,000 11 2000 730,000 5,840,000 \$150,000,000 636,158,500 \$1,272,317,000 12 1900 693,500 6,533,500 \$150,000,000 604,350,575 \$1,208,701,150 13 1805 658,825 7,192,325 \$150,000,000 574,133,046 \$1,148,266,093 14 1715 625,884 7,818,209 \$150,000,000 545,426,394 \$1,090,852,788 15 1629 594,590 8,412,798 \$150,000,000 518,155,074 \$1,036,310,148 16 1548 564,860 8,977,658 \$150,000,000 492,247,321 \$984,494,641 17 1470 536,617 9,514,275 \$150,000,000 467,634,955 \$935,269,909 18 1331 485,725 10,000,000 \$150,000,000 423,284,916 \$846,569,832 Total 10,000,000 \$5,000,000,000 \$2,250,000,000 8,714,500,281 \$17,429,000,561
30. 30. Solution:(cont.) 30 Net, \$/Yr Undiscounted Cum, \$ -\$1,000,000,000 -\$1,000,000,000 -\$2,500,000,000 -\$3,500,000,000 -\$1,500,000,000 -\$5,000,000,000 \$1,122,317,000 -\$3,877,683,000 \$1,122,317,000 -\$2,755,366,000 \$1,122,317,000 -\$1,633,049,000 \$1,122,317,000 -\$510,732,000 \$1,122,317,000 \$611,585,000 \$1,122,317,000 \$1,733,902,000 \$1,122,317,000 \$2,856,219,000 \$1,122,317,000 \$3,978,536,000 \$1,058,701,150 \$5,037,237,150 \$998,266,093 \$6,035,503,243 \$940,852,788 \$6,976,356,030 \$886,310,148 \$7,862,666,179 \$834,494,641 \$8,697,160,820 \$785,269,909 \$9,482,430,729 \$696,569,832 \$10,179,000,561 \$10,179,000,561 Undiscounted ROI 140.40% LRMC 0.83 \$/MM btu
31. 31. Solution:(cont.) 31 CAPEX, \$ OPEX, \$ Discounted Net @ HR Discounted Cum @ HR \$869,565,217 -\$869,565,217 -\$869,565,217 \$1,890,359,168 -\$1,890,359,168 -\$2,759,924,386 \$986,274,349 -\$986,274,349 -\$3,746,198,734 \$85,762,987 \$641,688,387 -\$3,104,510,347 \$74,576,510 \$557,989,902 -\$2,546,520,445 \$64,849,139 \$485,208,610 -\$2,061,311,834 \$56,390,556 \$421,920,531 -\$1,639,391,304 \$49,035,266 \$366,887,418 -\$1,272,503,886 \$42,639,362 \$319,032,537 -\$953,471,348 \$37,077,706 \$277,419,598 -\$676,051,750 \$32,241,483 \$241,234,433 -\$434,817,317 \$28,036,073 \$197,878,815 -\$236,938,502 \$24,379,194 \$162,246,148 -\$74,692,354 \$21,199,299 \$132,969,462 \$58,277,108 \$18,434,173 \$108,922,629 \$167,199,737 \$16,029,715 \$89,178,078 \$256,377,815 \$13,938,883 \$72,971,903 \$329,349,717 \$12,120,768 \$56,286,408 \$385,636,126 \$3,746,198,734 \$576,711,114 \$385,636,126 \$385,636,126 Dicounted NPV \$385,636,126 DROI 8.92% IRR 16.85% LRMC 1.84 \$/MM btu
32. 32. Solution:(cont.) 32 Production Rate vs. Time 1330 1430 1530 1630 1730 1830 1930 2030 0 2 4 6 8 10 12 14 16 Time, Years Gas Daily Production, MMSCFD
33. 33. Solution:(cont.) 33 Renue Streams -\$5 -\$4 -\$3 -\$2 -\$1 \$0 \$1 \$2 \$3 \$4 \$5 \$6 \$7 \$8 \$9 \$10 \$11 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Billions Time, Years Cum. Revenue, \$ Undiscounted Cum, \$ Discounted Cum @ HR
34. 34. Solution:(cont.) 34 + 50% - 50% OPEX \$1,516,394,804 \$2,373,578,821 CAPEX -\$534,694,602 \$4,424,668,227 HR \$385,636,126 \$4,785,163,869 Gas Price \$5,397,161,633 -\$1,507,188,009 NPV
35. 35. Solution:(cont.) 35 -2.0 -1.0 0.0 1.0 2.0 3.0 4.0 5.0 6.0 OPEX CAPEX HR Gas Price NPV, Billions \$ - 50% + 50% - 50% + 50% - 50% - 50% + 50% + 50% Project Current NPV
36. 36. 36