PRACTICAL APPLICATION OF SPECIFIC ENERGY ON BIT EVALUATION AND DRILLING OPTIMIZATION IN TAPUS FIELD

IATMI 25-26 PROSIDING, Simposium Nasional Ikatan Ahli Teknik Perminyakan Indonesia (IATMI) 25 Institut Teknologi Bandung (ITB), Bandung, 16-18 November 25. PRACTICAL APPLICATION OF SPECIFIC ENERGY ON BIT EVALUATION AND DRILLING OPTIMIZATION IN TAPUS FIELD Valentinus P,Eko R Yulianto,Winner Reynold; Eksploitasi Pertamina EP DOH Sumbagsel ABSTRACT Effectiveness in drilling has significant influence on the economic success of the oil and gas industry. Bit performance is a major factor in overall drilling costs as in Tapus field which has been developed to 21 wells (% were directional wells) per December 24 in a vertical and cluster system. The depth ranging from 2595 m (8512 ft) to 3654 m (11985 ft). Problem occurs when selecting the appropriate bit for drilling wells in Tapus structure, especially on 8½ hole trajectory. From total bits (type, IADC code, and brand) that have been used to drill on 8½ hole trajectory 65% of those bits yield low average ROP ( 1 ft/hr or 2mnt/m) whereas 7% of them yield quiet high average ROP ( 25 ft/hr or 8.5 mnt/m). There has been extensive research on bit performance during the past fifty years, and many people are still researching the subject and producing many papers and patents. This study will evaluate bit performance on Tapus field using Specific Energy because it is absolute, less ambiguous indicators of drilling performance and enhance the interpretation of drilling data to help analyzed factors that generally accepted as influencing bit performance. The result is a useful guide in term of depth for bit type and bit operating conditions that can yield to a higher ROP in Tapus field. It can be concluded that Specific Energy and its derivatives can be use as a simple quick look method to analyzed bit performance, and with help of appropriate pore pressure prediction and formation evaluation could be a powerful tools for a better selection in bit (type, IADC code, and brand), drilling fluid properties, and bit operating conditions BIT PERFORMANCE Effectiveness in drilling has significant influence on the economic success of the oil and gas industry. Bit performance is a major factor in overall drilling costs. This study will evaluate bit performance on Tapus field which will be drill up to 7 wells in 25. Bit performance is usually measured in terms of the cost per foot over an interval of a hole. To aid the assessment of the bit performance while drilling, the cumulative cost per foot/cumulative cost per meter can be calculated with cumulative value for rotating time and depth over regular, short interval; when the value of cost per foot starts to increase it is commonly assumed that the bit should be pulled out1.however the cost per foot is not an ideal measure for bit selection because of inaccuracies in measurement and prediction of hole section, trip time, rotating time and highly sensitive to change in rig cost per hour1. There has been extensive research on bit performance during the past fifty years, and many people are still researching the subject and producing many papers and patents. Using laboratory work-oriented and actual field observations, research studies correlate the relevance of proposed calculated diagnostic parameters on bit performance; therefore, after detecting the situation, the appropriate actions for specific events are recommended. Bourgoyne.et.al 2 stated the factors generally accepted as influencing bit performance: 1) bit type 2) formation characteristics 3) drilling fluid properties 4) bit operating conditions (RPM&WOB) 5) bit tooth wear 6) bit hydraulics Bit Type The bit type selected and the design characteristics of the bit have a significant 1

influence on ROP and effectiveness for the specific rock. Tooth length; number of cutters; cutter exposure or blade standoff; size, shape, surface, and angle of the cutter; and nozzle and jet design are some of the many bit characteristics which affect ROP and bit performance. 2,3,4,5 Bit condition, specifically the bit wear state, has influence on the effectiveness of drilling, and increased wear reduces ROP and bit performance. 2,3 Formation Characteristics The elastic limit and ultimate strength of the formation are the most important formation properties affecting ROP; however, the mineral composition of the rock can change the ROP. For example, rocks containing hard and abrasive minerals can cause rapid dulling of the bit teeth, and gummy clay minerals can cause the bit to ball up. The rock would be drilled very slowly in either case. 2, 3 Drilling Fluid properties The properties of the drilling fluid highly affect ROP. Density, rheological flow properties, filtration characteristics, solids content and size distribution, and chemical composition are some of the properties which have a high influence on bit performance. 2,3 For example, using OBM can increase ROP up to 3 times in lab tests. 3 Bit Operating Condition Weight on bit Weight on bit, WOB, is amount of the axial force applied to the bottom-hole formation to break the rock by the bit. It is calculated based on the difference between the measured weight of drillstring at the surface during off-bottom rotation and during the drilling operation. Typically, a plot of ROP vs. WOB, obtained experimentally with all other drilling variables held constant, will have the characteristic shape No significant ROP is obtained until the threshold WOB is applied. Then, the penetration rate increases rapidly with increasing WOB for moderate values of WOB, and at higher values of WOB, only slight improvements in ROP are observed. Finally, at extremely high values of WOB, ROP no longer increases. Despite increasing WOB, this behavior often is called bit floundering, and the point of maximum ROP is called flounder point. 2 The poor response of ROP at high values of WOB is usually attributed to less efficient bottom-hole cleaning. 2 In shale, increasing WOB more than flounder point decreases ROP, 4,5 and after flounder point, ROP is insensitive to WOB 3 Rotary speed (RPM) When all other drilling variables are held constant, ROP usually increases with RPM at low values. At higher values of RPM, the response of ROP to increasing RPM diminishes. 2 the poor response of ROP at high values of RPM usually is attributed to less efficient bottom-hole cleaning 2 In addition to previous information, choosing the appropriate WOB and RPM is highly influenced by types of rocks. For example, usually weak rocks drill with low WOB and high RPM, and strong rocks drill best with high WOB and low RPM. Also, low RPM increases the chance of stick slip, so the moderate RPM is preferred. 6 Bit Tooth Wear Most bits tend to drill slower as the bit run progresses because of tooth wear. The tooth length of milled tooth rolling cutter bits is reduced continually by abrasion and chipping. The teeth of tungsten carbide insert-type rolling cutter bits typically fail by breaking rather than by abrasion. Reductions in penetration rate due to bit wear usually are not as severe for insert bits as for milled tooth bits unless a large number of teeth are broken during the bit run. Diamond bits also fail from cutter breakage or loss of diamonds from the matrix. 2 Bit Hydraulics Increasing bit hydraulics and flow rate is widely considered to have a significant influence on ROP. The level of hydraulics achieved at the bit affects the flounder point of the bit 3 a flounder point is reached eventually when the cuttings are not removed as quickly as they are generated, so if the level of hydraulics is increased, a higher ROP will be achieved at the new bit flounder point. 2 The conventional way to assess drilling performance in the oil field is to compare actual performance to statistical standards derived from offset records. By their nature, these standards are subjective and variable. While they are ideal to monitor short-range performance and trends in well-known, older fields, they lack the power of physical models to establish absolute, technical performance standards. Several authors have proposed 2

models which the following parameters are used to represent drilling performance: Specific Energy, Mechanical Efficiency Force Ratio. Because the lack of data and for a simple and quick calculation we use only SE in this study. SPECIFIC ENERGY Specific energy is defined as the mechanical work done at the drill bit per unit volume of rock. It is related to both the strength of the rock and the efficiency of the drilling process. In general, a relatively low value implies efficient drilling and/or weak rock, and a high value implies ineffective drilling and/or strong rock. An equation used by Teale 7 to express specific energy is: WOB 12πNT SE = + AB AB ROP Where; SE = Specific Energy, psi WOB = Weight on bit, lbs Ab = Area Bit Area, sq in N = Rotary speed, rpm T = Bottom hole torque, ft-lbs ROP = Rate of penetration, fph A balled or worn bit requires higher specific energy than a new and/or clean bit for drilling the same rock under identical conditions 3. The bottomhole torque data is not always available for a bit run. Hence, difficulties often found to estimate bottomhole torque for calculating the specific energy.rabia 3 presented an alternative derivation for Specific Energy not requiring knowledge of torque, as follow: WOB. N SE = k. A. b ROP Where; SE = Specific Energy, psi k = Constant,dimensionless WOB Ab N ROP = Weight on bit, lbs = Area Bit Area, sq in = Rotary speed, rpm = Rate of penetration, fph The constant in the equation is approximate, however the most useful facet of any SE study of bit performance is the trend observed in the SE versus distance drilled plot. We use k=2., the same number as presented in Rabia s work. This constant only affect the magnitude of the plot, and not critical. 1 Pessiers and Fear 8 state that SE, are absolute, less ambiguous indicators of drilling performance and enhance the interpretation of drilling data in the: 1) detection and correction of major drilling problems, 2) analysis and optimization of drilling practices, 3) bit selection, 4) failure analysis, 5) evaluation of new drilling technologies and tools, 6) real-time monitoring and controlling of the drilling process, 7) analysis of MWD data and 8) further development expert systems. TAPUS FIELD OVERVIEW Figure 1. Tapus Subsurface well Tapus structure was found in December 1997 by drilling TPS-1 exploration well which has found economic oil and gas reserves. This structure has been developed to 21 wells Figure per December 1. Tapus Subsurface well loc 24 in a vertical and cluster system (figure 1). These development wells have shown that oil and gas production found in 1 to 2 reservoir layers in Talang Akar Formation sand. Tapus wells deep ranging from 2595 m (8512 ft) to 3654 m (11985 ft) with approximate drilling cost of each well are up to US$ 3 million. 3

Problem while selecting appropriate bit occur on drilling in Tapus structure, especially in 8½ openhole trajectory. Figure 2 show the average ROP plot of all 8½ bit that have been used in Tapus field for each well, note that blue box around certain well number shows that the well Twenty-one wells were drilled using ± 24 bit s brand from ± 7 bit producer from all over the world, 65% of those bits yields very low average ROP (less than 1 ft/hr or higher than 2mnt/m) whereas 7% of them yields rather high average ROP (higher than 25 ft/hr or less than 8.5 mnt/m).total amount of bit that have been use in drilling 8½ trajectory on 21 wells in Tapus field (excluding drilling cement and float collar+shoe) are ± 48 pcs. Some of the wells even need 4 to 5 bit for one 8½ openhole Average ROP (ft/h) 6 55 45 4 35 3 25 2 15 1 5 Bit Average ROP in Tapus Wells 1 2 3 4 5 6 7 8 9 1 11 12 13 14 15 16 17 18 19 2 21 Well Number ReedHycal DS7F Med (PDC) HallSecurity FM2546/FM3546 (PDC) HallSecurity FM2846/FM3846 (PDC) HallSecurity FM2665/FM3665 (PDC) HallSecurity S84F 571 S-M (Tricone) HughesChrist AG526 S-M (PDC) HughesChrist AG536 S-M (PDC) HughesChrist AG445 S-M (PDC) HughesChrist AG545 Med (PDC) HughesChrist G535 Med (PDC) HughesChrist G447 M-H (PDC) SmithGeod S94 S-S (PDC) SmithGeod M7 M-H (PDC) SmithGeod M91 S-M (PDC) ReedHycal DS11HG Med (PDC) ReedHycal RS192HF S-M (PDC) Precision UD513 (PDC) Precision UD519 (PDC) Smith FP51P (PDC) Smith M3DX (PDC) Varel V517 (PDC) DPI MC45LTM (PDC) Smith MKBX ReedHycal DS168DGJNV trajectory. was vertically drill. It s clearly shown from data which state above that an appropriate bit selection and drilling optimization are extremely needed so an optimum bit performance could be reach in the future for development wells in Tapus field. DATA COLLECTION Figure 2. 8½ Bit Average ROP in Tapus Wells; blue boxes shows vertical wells Well data were collected from several resources. Drilling parameter was collected from mud 4

logger report, because of data limitation only TPS-9 to TPS-21 (excluding TPS-1 and TPS-12) could be retrieved. From those 11 wells, 3 wells the result can be seen in Figure 4. The graphic shows that in the same depth for every wells yields different SE value. Some of the wells Drilling Parameter ROP (mnt/m) WOB (Ton) RPM Torq (ftlbs) MW (SG) SPP (psi) Well TPS- TPS- TPS- TPS- TPS- TPS- TPS- 21 2 TPS-19 18 17 14 13 11 average 7.7 7.4 25.5 19.8 28.1 13. 11.6 21.1 median 6. 5.7 18.8 14.6 2.6 11.2 6.9 16. stddev 7. 7.6 22.5 22.5 22.4 9.6 14.9 16.3 average 5.4 4.1 2.9 3.6 5.8 9. 6.7 5.4 median 4.9 3.7 2.8 2.9 5.5 4.5 6. 4.6 stddev 2.7 2.1 1.1 2.3 2.3 2.2 2.9 2.9 average 232 161 144 219 14 22 138 74 median 222 162 89 223 6 223 95 69 stddev 38 18 73 32 82 62 64 14 average 7556. 6894.3 1511. 336.7 1469.5 24.4 7392.4 184. median 8124.1 6722.1 9856.8 3648.3 1447.4 5. 7731.4 188.9 stddev 2632.3 1171.9 47. 13.8 192.7 28.2 242.4 37.9 average 1.142 1.139 1.148 1.172 1.158 1.151 1.166 1.121 median 1.141 1.141 1.141 1.171 1.162 1.151 1.165 1.12 stddev.3.14.1.4.15.2.9.14 average 1617 26 146 1973 164 173 184 1526 median 1638 262 1151 1977 1591 1788 1827 1673 stddev 139 11 146 2 17 159 31 average 8 541 533 537 533 531 3 539 GPM median 51 541 539 544 537 534 5 572 stddev 4 16 23 4 29 2 45 64 have uncompleted data (TPS-9, TPS-15, and TPS-16),.To have a better comparison then only drilling parameters from 8 wells would be yields rather high SE value compared to other wells. Every bit which have low value for each depth listed in table 2. Results of the calculation calculated. Table 1. Drilling Parameter in Tap Cutting logs, open hole logs, and log interpretation (Elan) also collected as a supporting data to gave a better and clearer view of the formation characteristics that have been penetrated by the wells above. COMPARISON OF SE VALUE IN FIELD Table 1. shows statistical data of drilling parameters that have been used in the calculation. Note that the trend of the ROP data tends to increase in Tapus newest wells. The data then used to calculate SE value from each well for every depth (figure3).calculated SE value then plotted toward depth (in TVD), 5

1 1 2 2 3 1822 1861 1899 1938 1976 215 254 293 2131 217 229 2248 2287 2326 2365 244 2443 2482 2521 256 2599 2638 2677 2717 2756 2794 TPS-21 1 1 2 2 3 188 1858 197 1956 25 254 213 2152 223 2252 232 2353 243 2454 26 2558 261 2662 2713 2766 2819 2872 2925 2978 331 384 TPS-2 1 1 2 2 3 184 1852 1899 1947 1995 243 29 2137 2184 2232 2279 2327 2374 2422 247 252 2568 2616 2664 2712 276 288 2856 294 2952 TPS-19 1 1 2 2 3 193 1974 219 263 218 2153 2197 2244 2287 2334 2382 2429 2476 2524 2574 2624 2674 2724 2774 2824 2873 2923 2972 322 372 TPS-18 1 1 2 2 3 19 1997 243 288 2131 2178 2225 2272 2319 2366 2413 2459 21 2548 2594 2627 2674 2721 2767 2814 286 297 2954 31 348 395 TPS-17 1 1 2 2 3 1815 1861 197 1953 1998 243 287 213 2173 2216 2259 232 2345 2387 243 2475 2518 2563 268 2653 2699 2744 279 2836 2882 2928 TPS-14 1 1 2 2 3 1991 236 284 2132 218 2228 2276 2324 2369 2416 2461 27 25 2595 2638 2684 2729 2774 2817 2861 293 2948 2994 338 385 3133 TPS-13 1 1 2 2 3 1972 227 281 2136 2191 2246 231 2356 2411 2466 252 2574 2629 2684 2737 2792 2846 291 2956 311 366 3117 3172 3226 3279 3333 TPS-11 Figure 3. SE Value of each well Table 2. Summary of bit with lowest calculate 6

Depth (TVD) (m) Meterage (m) IADC Code Well Brand 183 1832 29 M433 TPS-19 Hughes Christensen G447 1833 1894 61 M223 TPS-2 Smith Geod M91PX 1895 192 25 M223/M323 TPS-2/TPS-14 Hughes Christensen AG536/Smith Geod M91PX 1921 1948 27 M223/M433 TPS-19/TPS-2 Hughes Christensen G447/Smith Geod M91PX 1949 218 69 M223M322 TPS-2/TPS-18 Reed Hycalog RS192HF/Smith Geod M91PX 219 244 25 M323 TPS-14 Hughes Christensen AG536 245 286 41 M223 TPS-2 Smith Geod M91PX 287 213 43 M322 TPS-18 Reed Hycalog RS192HF 2131 2156 25 M322/M323 TPS-18/TPS-19 Reed Hycalog RS192HF/Reed Hycalog DS11HG 2157 2182 25 M323/M223 TPS-13/TPS-2 Hughes Christensen AG535/Smith Geod M91PX 2183 229 26 M322/M323 TPS-18/TPS-19 Reed Hycalog RS192HF/Reed Hycalog DS11HG 221 2228 18 M323/ TPS-13/TPS-17 Hughes Christensen AG535/Precision UD 513 2229 2246 17 M223 TPS-2 Smith Geod M91PX 2247 226 13 M323 TPS-19 Reed Hycalog DS11HG 2261 229 29 M323 TPS-13 Hughes Christensen AG535 2291 2337 46 M323 TPS-19 Security FM 2665 2338 237 32 M223 TPS-2 Smith Geod M91PX 2371 2441 7 M223 TPS-19 Smith Geod M91PX 2442 2469 27 M322 TPS-18 Reed Hycalog RS192HF 247 2556 86 S324 TPS-2 Reed Hycalog DS7F 2557 2583 26 M221/M323/S324 TPS-11/TPS-13/TPS-2 Hughes C AG526/Hughes C AG535/Reed H DS7F 2584 2614 3 M221 TPS-11 Hughes Christensen AG526 2615 2639 24 S324 TPS-17/TPS-2 DPI MC45TLM/Reed Hycalog DS7F 264 2661 21 S324 TPS-2 Reed Hycalog DS7F 2662 2749 87 M323 TPS-19 Smith Geod M7PX 27 2773 23 S324 TPS-2 Reed Hycalog DS7F Hughes Christensen AG526/Reed Hycalog 2774 2852 78 M221/M323 TPS-11/TPS-2 DS7F 2853 2875 22 S324/M323 TPS-19/TPS-2 Reed Hycalog DS7F/Smith Geod M7PX 2876 296 84 S324 TPS-2 Reed Hycalog DS7F 2961 2989 28 M433 TPS-13 Hughes Christensen G447 299 37 8 M433 TPS-13/TPS-18 Hughes Christensen G447/Smith Geod MKBX 371 384 13 - TPS-17 DPI M 46 LTMR 385 313 45 M323 TPS-11 Hughes Christensen AG536 3131 3323 192 M433 TPS-11/TPS-13 Hughes Christensen G447 (table 3) then summarized and could be used as guidance for choosing an appropriate IADC Code especially in 8½ openhole trajectory. Few interesting things have to be studied furthermore concerning calculated value of SE that have stated above. SE value differ for the same bit and drilling depth for different well. Take a look at DS7F bit (TPS-2,21) in figure 5, for an example. This same bit have been used in TPS-2,TPS- 2ST,and TPS-21 wells, while in the last two wells it shows good performance (>25 ft/h or < 8.5 mnt/m),the bit show a poor performance (<1 ft/h or >2 mnt/m) in TPS-21 well. 7

- Bit operating condition (RPM & WOB) : differences found in average WOB and SE (Kpsi) 3 275 2 225 2 175 1 125 SE vs Depth in Tapus Field Tps21 Tps2 Tps19 Tps18 Tps13 Tps17 Tps14 Tps11 1 75 25 184 24 224 244 264 284 34 324 Table 3. IADC Code by Depth Depth(TVD) (m) RPM that have been used for each case, for DS7F bit, in TPS-21 higher RPM Figure 4. SE vs Depth in Tapus Field detected while WOB relatively the same - Bit hydraulics: at relatively the same BHA for DS7F bit, TPS-2 use higher Depth (TVD) (m) IADC Code 18-24 M223/M323 24-29 S324/M323 29-34 M433 Drilling data that generally accepted as influencing bit performance have been evaluated for those three wells as follow: - Formation characteristics: all wells penetrate the same structure and the same depth relatively. MLU reports indicate an identical formation composition. - Drilling fluid properties: average mud weight use still at the same range, approximate SG ±1.14. 8 Well Drillling Parameter TPS-21 TPS-2 ROP Table4.. average Drilling Parameter 11.627 DS7FGV 6.871 (mnt/m) median 8.11 5.543 WOB (Ton) RPM Torq (ftlb) MW SPP (psi) GPM stddev 12.139 5.168 average 6.254 5.45 median 5. 5. stddev 3.729 1.94 average 293.986 165.196 median 32. 164. stddev 21.538 13.771 average 85.953 749.658 median 959.2 686. stddev 2757.167 125.339 average 1.141 1.148 median 1.141 1.141 stddev..12 average 1625.553 2121.286 median 1635. 2123.9 stddev 89.545 78.961 average 7.658 538.62 median 6.788 538.33 stddev 81.999 14.579

- GPM,higher recorded SPP,and smaller size nozzle. It could be assumed that driliing hydraulic applied in TPS-2 is better than TPS-21. - Bit Tooth wear: one thing should be noted here that in TPS-21 well DS7F bit wear condition was cored after POOH with high SE value, while TPS-2 have an extremely low SE value at the same depth, it s a pity that bit wear condition data cannot be measured because TPS-2 BHA have left behind in the well as a result of failed to overcome a stuck pipe condition. CONCLUSION 1. Specific Energy and its derivatives can be use as a simple quick look method to analyzed bit performance 2. Specific Energy can be used as a guideline to choose an appropriate bit type. 3. Tapus field can be drilled faster with IADC type guidelines in table 3. With help of an appropriate bit operating condition and hydraulic. 4. Bit operating condition and hydraulic can be a great effect on ROP if not been applied appropriately Dissertation,Louisiana State University, August 1998 4. T.M. Warren and W.K. Armagost, Laboratory Drilling Performance of PDC Bits, SPE15617, 1986 5. T.M. Warren and A. Sinor, Drag Bit Performance Modeling, SPE 15618, 1986 6. Arash Aghassi, Investigation of Qualitative Methods for Diagnosis of Poor Bit Performance Using Surface DrillingParameters Thesis,Louisiana State University, May 23. 7. Teale, R.: The Concept of Spesific Energy in Rock Driliing.,Intl. J. Rock Mech.Mining Sci,1962 8. Pessier,R.C and Fear,M.J.: Quantifying Common Drilling Problems With Mechanical Specific Energy and a Bit-Specific Coefficient of Sliding Friction, SPE 24584,1992 SE (kpsi) 3 2 2 1 1 SE vs Depth DS7F Tps21 Tps2 2 26 27 28 29 3 Depth (m) Figure 4. SE vs Depth DS7F REFERENCES 1. Rabia,H.,Farrely, M. Bit Performance and Selection : A Novel Approach SPE/IADC 16163,1987. 2. Bourgoyne, A.T. et al, Applied Drilling Engineering, SPE Textbook Series Volume 2,1991 3. John Rogers Smith, Diagnosis of Poor PDC Bit Performance in Deep Shales, 9