THE FIRST SUCSESSFUL MULTI STAGED FRACTURING IN A DEEP VOLCANIC GAS RESERVOIR IN JAPAN

THE FIRST SUCSESSFUL MULTI STAGED FRACTURING IN A DEEP VOLCANIC GAS RESERVOIR IN JAPAN Hiromi Sugiyama, Teikoku oil, co., ltd. Abstract The first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka gas field, Niigata Prefecture, Japan, was successfully completed using six propped fracture treatment stages. During two propped fracture treatments pumped in early 9s, treatments failed miserably with only about 2% of the designed proppant placed before job termination due to premature screen-outs. Recent study and feed back from the two premature screen out experiences suggested that near wellbore tortuosity, which caused multiple fractures to grow, was estimated to be higher than anticipated. In this condition, the net fracturing pressure became increasing due to individual fractures press each other with the fracture width keeping narrow. Increasing net pressure led to the high surface treating pressure, limited injection rate, finally ended in premature screen out with low proppant concentration. The new treatments in Minami-Nagaoka focused on the ability to mitigate the adverse effects of multiple hydraulic fracture propagation and the accompanying severe near-wellbore fracture tortuosity. Many unconventional changes, including completion changes to obtain highest possible injection rates to enhance proppant placement, aggressive proppant slug strategy, real-time fracture treatment analysis, gel testing for minimization of proppant damage, careful perforation placement, quality control, extreme overbalance perforating, and use of small-grained proppant, resulted in successful stimulation and favorable production response. This paper focuses on these new design concepts and also the fracturing results. Introduction Volcanic rocks play a major role for hydrocarbon accumulation in Japan. The exploration activity of Middle Miocene volcanic rocks started in 195 s. Since then, some of the major oil and gas fields in Japan have been discovered in this play type. The Minami-Nagaoka gas field, the largest gas field in Japan, is located in northern central Japan (Figure 1). The field was discovered in late 197 s and came on stream in 1984. The reservoir consists of the submarine-erupted volcanic rocks (rhyolite) of Middle Miocene age at the depth of more than

4, m with a maximum hydrocarbon column off 1, m under the high-temperature (18degC), high-pressure (58MPa) condition. The core analysis of reservoir section shows the average porosity of around 5 15 % and low permeability in range from.1 to 1 md. Main pores are generated by the dissolution of the volcanic glass and they are interconnected by natural fractures. The reservoir is very heterogeneous due to its drastic lithofacies change and intense alteration. The highly productive intervals coincide with the development of glassy rhyolite, which is abundant of dissolution pores and natural fractures. In the northern part of the field, however, such glassy rhyolite underwent intense silicification and dissolution pores are underdeveloped compared with those in the southern part. In addition, the poor development of natural fracture networks in the northern part resulted in the low productivity of natural gas. Review of Previous Treatments In the deep heterogeneous volcanic rock, the classical concept of a single-planar fracture could not explain the extremely high net fracturing pressures (of order 28MPa, see Figure 2) that led to two premature screen-outs (only about 2 % of the designed proppant placed) in the early 199s. Several mechanisms for these high net fracturing pressures were considered, but only two were considered valid: Higher effective Young s modulus to increase fracture stiffness. This would require a material with a higher modulus than steel, and this explanation was therefore not valid; Higher closure stress in the layers surrounding the pay zone. This would require a closure stress contrast of order 4+ MPa at a depth of 42, m, and this was also disregarded as logs did not show substantial lithology changes; Fracture tip effects. Earlier observations of high net fracturing pressures were implemented in the fracture growth model, but although adding these effects in the model did help to explain a significantly higher net pressure in comparison to linear-elastic fracture models, tip effects alone could not explain the extreme level of the net fracturing pressure; Simultaneous propagation of multiple hydraulic fractures. When assuming that multiple hydraulic fractures propagate simultaneously during the fracture treatment, the extremely high fracturing pressures can be successfully matched, and the resultant production due to extremely short propped length is consistent with both the premature screen-outs and the post-frac production performance. Combined analyses of fracturing pressure and subsequent production performance strongly suggest the creation of multiple fractures: Attributing all of the elevation in net fracturing pressure to extreme fracture tip effects (Figure 3, scenario 1) would result in a fracture width of roughly 2 inches. Clearly this is inconsistent with the

very premature screen-out on both treatments. Utilizing a scenario (scenario 2) where tip effects play no role and the only mechanism for high net pressures comes from the simultaneous propagation of multiple hydraulic fractures is inconsistent with the successful placement of some proppant. In this case, individual fracture width would be smaller than the 2/4 mesh proppant grain diameter. Therefore, a third scenario where both fracture tip effects and multiple hydraulic fractures play a role seems most likely. For this scenario, the fracture is wide enough to accept the low proppant concentrations, but proppant placement problems occur for higher concentrations as the average fracture is only about 3 proppant grains wide. Although the actual fracture growth behavior is bounded between scenario 1 and scenario 2, scenario 3 can be somewhat flexible fracture tip effects may actually be somewhat more or less important than multiple fractures. It is clear, however, that multiple hydraulic fractures must be present to explain all observations. Design Concept for the New Well Numerous recommendations have been made for stimulation and completion strategy in the newly drilled well, MHF#1. These assumptions have been based on the analysis results of the failed propped fracture treatments, and on experience from a variety of other oil and gas fields in the world with similar (albeit not as severe) proppant placement problems as were experienced in these first two wells. In summary, the following design goals were used for the propped fracture treatments in well MHF#1: Conduct 6 propped fracture treatments targeting a 21 m half-length (assuming rectangular fracture shape) and a 42 m fracture height. We determined that a production response of 2 MN m 3 /d would be economical to conduct further field development using propped fracture stimulation in new wells in the Northern parts of the Minami-Nagaoka gas Field. Obtain at least one monolayer (~.2 lb/ft 2 ) of 3/6 mesh Bauxite proppant to minimize significant stress-induced damage. Crushing can be significantly limited if at least a proppant monolayer is present within an individual fracture. Observe every proppant stage to hit perfs before increasing proppant concentration at surface. This methodology can be utilized as an advance-warning system for upcoming near-wellbore screen-outs. This requirement makes each stage at least the size of the wellbore volume, or about 2 bbl. The long proppant concentration steps and relatively small treatment size generally limit max proppant concentration to 4 lb/gal. Select 3/6 mesh Bauxite as the proppant of choice. 3/6 mesh Bauxite was selected instead of the 2/4 mesh Bauxite used on two previous treatments for two reasons: (1) smaller grain diameter will allow it to be pumped through smaller fracture width farther away from the well. and, (2) it provides a stronger layer with higher conductivity at lower proppant concentration. Select CMHPG Zirconate as the fluid of choice, using a base gel loading of 6 ppt. In case of a pressure increase reaction upon repeated proppant slugs, a 7 ppt CMHPG Zirconate system

should be used. Test crosslink time every time on location prior to the mini frac and propped fracture treatment is critical, as crosslinking time can fluctuate with ph, especially as the pre-mixed gel ages. Reduce perforated interval length significantly from several 1s of meters in the previous two wells to 6 m in MHF#1 in an attempt to minimize fracture initiation points and to create a simpler initial fracture geometry. Utilize a cautious proppant slug strategy using various proppant slugs during mini frac and pad to minimize near wellbore friction. Results and Findings Four out of six propped fracture treatments were conducted as designed. One treatment screened-out halfway during the treatment, and one treatment screened-out on a proppant slug. It was never necessary to clean out the well with coil tubing between stages. Despite the fact that the average treatment size called for 36 ton of proppant placed per treatment, total of about 14 ton out of the 226 ton of proppant was pumped (see Figure 4). In comparison to the two previous fracture treatments in Minami-Nagaoka in 1989 and 1991, where only 12 and 7 ton of proppant could be placed and treatments prematurely screened-out, this project delivered 4 successful propped fracture treatments, including one with a new Japanese propped fracture treatment record of 41 ton of proppant placed in formation in stage 4 in MHF#1. Initial production response was significantly above economic target of 2 Mm 3 /d at about 45 Mm 3 /d. This rate appeared to hold up well during a 3-month production test conducted in early 22. Production data analysis of isochronal tests indicates 96% damage of placed fracture conductivity, mostly likely due to multiple hydraulic fractures. High surface treating pressures were a major concern on all stages except stages 2 and 4, making it extremely challenging to successfully finish a treatment. ISIP gradients were generally significantly above the overburden gradient of 1.5 psi/ft between.9 1.3 psi/ft (see Figure 5), and slurry rates of 1-25 bpm could generally be achieved. Surface treating pressures were high due to a combination of extremely high net fracturing pressures, high near-wellbore and mid-field tortuosity, and high fracture closure stresses were all observed to be relatively high, making this an extremely challenging fracturing environment. It was therefore critical for the success of this fracturing campaign to have a maximum wellhead pressure of 93MPa. Net fracturing pressures were extremely high at an average of about 2 MPa at the end of the breakdown injection and about 24 MPa at the end of the crosslink gel minifrac (see Figure 6). To match these observed net pressure, we used an average of 13 equivalent simultaneously propagating multiple hydraulic fractures to match the breakdown injection, and 9 equivalent simultaneously propagating multiple hydraulic fractures to match the crosslink gel minifrac (see

Figure 7). Fracture closure stress was much more variable than initially expected from the dipole sonic log extrapolation. Instead of a closure stress around.77 psi/ft, which was observed in the single fracture treatments in the previous two wells, the actual closure stress gradient in MHF#1 varied between.61 psi/ft and.94 psi/ft (see Figure 8). Closure stress was determined from several diagnostic pressure decline plots, such as pressure vs. square-root time plot, G-function plot, log-log plot of delta pressure and rate normalized plot. There appears to be a potential correlation between Young s modulus, density of natural fractures and the fracture closure stress: closure stress is high in rock with a high modulus and low density of natural fractures, and low in heavily naturally fractured rock. This indicates that the mechanism for the change in closure stress could be due to induced displacement at plate boundaries, possible due to the subduction zone off the Eastern side of Japan. Near-wellbore friction was high at an average of about 7MPa at 2 bpm at the end of the crosslink gel minifracs (see Figure 9). In addition to near-wellbore tortuosity., we also observed about 1 MPa of mid-field tortuosity at the end of the crosslink gel minifracs. The mid-field tortuosity manifested itself in rapid pressure declines directly following a shut-in, indicating a choke for fluid flow farther away inside the fracture. The relatively slow screen-out behavior that was observed in stages 3 and 6, and some of the delayed proppant reactions during proppant slugs are contributed to proppant bridging in the mid-field of the fracture. Pressure sensitivity to proppant slugs and changes in proppant concentration was extreme. Although the very conservative approach was taken to only pump low-concentration proppant slugs (.5 2. ppg, 25 bbl), most proppant slugs resulted in at least a 1.4-4.1 MPa increase in pressure, while there was also a few extreme cases such as a screen-out on a 1.5 ppg proppant slug during the pad of stage 5 (see Figure 1). In light of the observed treatment behavior, original designs were significantly changed: larger pad, slower proppant concentration increases, and more slugs. Clean treatment volumes in the original design increased from 133 bbl to 185 bbl in the actual treatments, whereas average pad percentage increased from an average 24% to 36%. These changes were mainly due to the fact that leakoff was higher than expected and that prop frac slurry efficiency was only about 31% instead of the anticipated 5%. This caused us to run out of fluid while sand was still left on location. The amount of fluid used was much higher than initially thought, while the average amount of proppant per treatment was smaller than initially expected due the necessity to watch every proppant concentration hit perfs before continuing to the next proppant concentration. Conclusions Four out of six propped fracture treatments were conducted as designed, supported by a real-data feedback engineering approach. This was a significant improvement over past failures to place

significant amounts of proppant in fractures in this environment. In the light of the extremely challenging fracture treatment behavior, we believe that all of our newly introduced design concepts were critical to achieve proppant placement (although we do not know how much each of these contribute individually): Smaller proppant grain size: 3/6 mesh Bauxite instead of 2/4 mesh Bauxite; Utilizing short perforated interval of 6 m instead of several 1s of meters in the previous two wells; Cautious proppant slug strategy; Maximizing pump rate by using larger tubing size (4.5 instead of 3.5 ) and higher maximum wellhead pressure; Increasing fluid viscosity during treatment by using high gel loading; Creating favorable near-wellbore geometry by utilizing Extreme Overbalance Perforating (EOB). Initial production response was significantly above economic target of 2M m 3 /d at about 45 Mm 3 /d. With this economic production rate, further field development is expected within a few years. These new fracturing design concepts and approaches could be applicable to the fields, which has similar difficulties to place proppant. References 1. Sato, K., Wright, C.A., and Ichikawa, M.: Post-Frac Analyses Indicating Multiple Fractures Created in a Volcanic Formation, paper SPE 39513 presented at the 1998 India Oil and Gas Conference, New Delhi, Feb 1-12. 2. Weijers, L., C.A. Wright, H. Sugiyama, K. Sato, L. Zhigang: Simultaneous Propagation of Multiple Hydraulic Fractures - Evidence, Impact and Modeling Implications, SPE paper 64772 presented at the 2 International Oil and Gas Conference and Exhibition, Beijing, Nov. 7-1. 3. L. Weijers, L.G. Griffin, Pinnacle Technologies; H. Sugiyama, T. Shimamoto, and S. Takada, Teikoku Oil Company; K.K. Chong, J.M. Terracina, Halliburton, and C.A. Wright, Pinnacle Technologies. "The First Successful Fracture Treatment Campaign Conducted in Japan: Stimulation Challenges in a Deep, Naturally Fractured Volcanic Rock"

Figure 1 Index Map 1 3 Net Pressure 25 Net pressure (psi) 1 Net Pressure Rate Prop. Conc. 2 15 1 Injection Rate Prop. Conc. 5 1 1 1 Treatment time (min) 1 Figure 2: Treatment data for fracture treatment in naturally fracture Minami Nagaoka reservoir, Net

fracturing pressure was as high as 4, psi Figure 3: (top) Treatment data for fracture treatment in naturally fracture Minami Nagaoka reservoir; (bottom) Example of observed and calculated net fracturing pressures and fracture dimensions for a single fracture versus ~3 equivalent simultaneous propagating fractures. Observed net fracturing pressures can only be matched by using a relatively large number of equivalent multiple fractures. MHF#1 Proppant Pumped 11 Total proppant pumped (incl. slugs) 1 Total proppant in formation (incl. slugs) Design proppant (excl. slugs) 9 Proppant slugs pumped 8 Proppant (klbs) 7 6 5 4 3 2 1 1 2 3 4 5 6 Stage Figure 4: Amount of proppant placed per stage in well MHF#1

MHF#1 Stabilized ISIP Gradient ISIP Gradient (psi/ft) 1.5 1.4 1.3 1.2 1.1 1..9.8 Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 6.7.6 BD #1 XL MF 1 PF End Injection Figure 5: ISIP gradient MHF#1 Net Pressure Progression Net pressure (psi) 7 6 5 4 3 2 Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 1 BD #1 XL MF 1 PF End Injection Figure 6: Net Pressure

MHF#1 Multi Frac Opening Factor Progression 3 MF Opening Factor 25 2 15 1 Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 5 BD #1 XL MF 1 PF End* Injection Figure 7: Multiple fracture opening factor 4 45 41 MHF#1 Closure Stress Gradient vs. Depth stage 6 Original stress profile Pressure decline analysis Calibrated stress profile Depth (m TVD) 415 42 425 stage 4 MF stage 4 BD stage 5 43 stage 3 435 stage 2 stage 1 44.5.6.7.8.9 1 Fracture closure stress gradient (psi/ft) Figure 8: Closure stress gradient

MHF#1 Normalized NWB Tortuosity 4 NWB Tortuosity at 2 bpm (psi) 3 2 1 Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 BD #1 XL MF #1 PF End Injection Figure 9: Normalized near wellbore tortuosity

Pressure response(psi) 8 6 4 2-2 Stage #1 MF#1 MF#2 PF..5 1. 1.5 2. Slug Concentration(ppa) Pressure response(psi) 2 Stage#4-2 -4-6 -8-1 MF PF..5 1. 1.5 2. Slug Concentration(ppa) 2 Stage#2 25 Stage#5 Pressure response(psi) 15 1 5-5 MF PF Pressure response(psi) 2 15 1 5 MF PF -1..5 1. 1.5 2. Slug Concentration(ppa)..5 1. 1.5 2. Slug Concentration(ppa) 1 Stage#3 25 Stage#6 Pressure response(psi) 8 6 4 2 MF PF Pressure response(psi) 2 15 1 5 MF PF..5 1. 1.5 2. Slug Concentration(ppa) -5..5 1. 1.5 2. Slug Concentration(ppa) Figure 1: Proppant slug reaction