Acidising Case Study – Kawerau Injection Wells
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PROCEEDINGS, Thirty-Sixth Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, January 31 - February 2, 2011 SGP-TR-191 ACIDISING CASE STUDY – KAWERAU INJECTION WELLS Yoong Wei Lim1, Malcolm Grant2, Kevin Brown3, Christine Siega1 and Farrell Siega1 1 Mighty River Power, 283 Vaughan Road, Rotorua, New Zealand 2 MAGAK, 208D Runciman Road, RD2 Pukekohe 2677 New Zealand 3 GEOKEM, P.O. Box 30-125, St Martins, Christchurch, New Zealand e-mail: 1 [email protected]; ABSTRACT Brine at the Kawerau Geothermal Limited (KGL) plant was injected into three injection wells (KA43, KA44 and PK4A). Since plant commissioning, the capacity of the wells declined to the point where well intervention was necessary to avoid loss of generation. Investigative work was initiated with multi-rate injection tests which found that the injection index of the wells had declined significantly to approximately half of pre-utilisation levels. Further geochemistry analysis identified that the most likely source of injectivity decline was scaling due to colloidal silica forming in the formation. KA44 and PK4A were acidised using a standard 10% hydrochloric acid pre-flush followed by a 10%:5% HF:HCL mud acid solution. A 2” coil tubing unit with a 5 hole 45º nozzle bottom hole assembly was used giving a maximum pump rate of 3.5 - 4.0 barrels per minute. Feedzones were acidised one at a time starting with the deeper zones. Post well injection tests identified that the acidising Figure 1: Location of the Kawerau Geothermal Field had recovered the injectivity of the deeper feedzones but the shallower feedzones remain blocked with Silica precipitation at Kawerau has been a concern scale. The injectivity index at PK4A improved from since the design phase as the silica saturation index 50 t/h.b to 84 t/h.b while KA44’s gross injectivity (SSI) is approximately 1.9 at injection temperature. index increased from 25 t/h.b to 50 t/h.b. Camera To prevent deposition, an acid inhibition system (or runs carried out before and after acidising revealed pH modification) was installed at Kawerau (Horie excellent scale removal from the perforated liners. 2009). Pre and post acidising High Temperature Casing Corrosion (HTCC) logs also showed that the acid had Since plant commissioning, routine monitoring of the not caused any measurable corrosion in the casings. wells identified declines in the well capacity. Subsequent investigative work was initiated to INTRODUCTION confirm declines and identify the root cause. Three injection wells (KA43, KA44 and PK4A) were used to inject brine from the Kawerau Geothermal INVESTIGATIVE WORK Limited (KGL) plant (Figure 1) since plant As an initial step in the investigation, multi-rate commissioning in August 2008. injection tests were carried out on all three wells and identified that the injectivity indices had declined to approximately half of pre-utilisation levels (Table 1). Non- linear injectivity was also observed from the tests suggesting restriction at the well face. Table 1: Comparison between original well performance and July 2009 performance. Well Original II as of July 2009 (t/h/b) II (t/h/b) II at low rate II at high rate KA43 45 13 25 KA44 97 45 60 PK4A 100 42 75 The decline in injectivity is in contrast to the performance elsewhere. In the absence of deposition problems, injectivity should increase roughly with the square root of the time injecting, as shown in Figure 2. The injectivity is higher under stimulation, for the same time injecting, as cold water is used for Figure 3: Low magnification of the 2µm stainless injection whereas the waste water is hotter. steel filter from LP brine. Figure 2: Injectivty history of RK21 during stimulation with cold water and under operation with waste water. Not only did the Kawerau wells not follow the trend of increasing injectivity with time, but injectivity declined. Figure 4: Low magnification of the 2µm stainless Brine was also filtered through a Swagelok 2 µm steel filter from injection wellhead brine. stainless steel filter at the LP separator and injection wellhead. An environmental scanning electron Interpreting the results of this test, it was postulated microscope (E-SEM) was then used to investigate the that the most likely cause of scaling is due to precipitates. The LP separator filter (Figure 3) had a colloidal silica scaling. Subsequent downhole small amount of debris which mainly consisted of camera runs done in all wells identified that the silica. The injection wellhead filter (Figure 4) had a wellbores were relatively clean confirming that the larger amount of material deposited with restriction was occurring at the well face. compositions similar to the LP filter. Unfortunately, both the spinner and camera runs in KA43 also identified a shallow casing break and the subsequent sleeving job was not successful. Thus, plans to acidise KA43 were abandoned and preparation work focused on acidising KA44 and PK4A. WELL ACIDISING KA44 (Big Hole) All depths are referred to the Casing Head Flange BJ Services were contracted to design and carry out the acidising. A 2” coil tubing unit with a 5 hole 45º RT-CHF = 9.6m nozzle bottom hole assembly was used giving a 30" Casing maximum pump rate of 3.5 - 4.0 barrels per minute. 12.4m The use of a CTU was hoped to provide better acid Tie Back = 345.4m placement as it can be moved to each zone prior to 20" Casing (ID=0.486m) pumping acid. 394.4m kick-off point 398.4m A traditional 10% hydrochloric (HCL) to 5% hydrofluoric (HF) mud acid was used for this project Top of 10-3/4" liner (ID=0.253m) along with corrosion inhibitors, iron chelating agents 1438.4 mMD/ 1382.4 mVD 13-3/8" (ID=0.315m) Production Casing Shoe 1468.04 mMD/ 1411.3 mVD and gelling agents. The standard 10% HCL preflush Zone 5 140 bbls HCL 1450 - 1480m Zone 4 200 bbls HCL:HF 220 bbls HCL was also used to dissolve carbonate minerals in the 320 bbls HCL:HF 1590 - 1615m formation (Kalfayan, 2008, p70). Both wells were 1680 - 1710m Zone 3 120 bbls HCL 180 bbls HCL:HF quenched prior to the acidisation and a multi-rate 1860 - 1900m Zone 2 injection test along with downhole camera and High 270 bbls HCL 2010 - 2035m 420 bbls HCL:HF Temperature Casing Corrosion (HTCC) runs was 2052 - 2084m carried out to identify the pre-acidising conditions. Zone 1 240 bbls HCL The pre-flush was then carried out followed by the 350 bbls HCL:HF 2500 - 2560m Bottom of 10-3/4" liner 2582.4 mMD/ 2448.4 mVD mud-acid mixture. Permeable zones were divided Total Depth = 2582.4 mMD/ 2448.4 mVD into groups and acidised using a “bottom-up” Figure 5: Wellbore schematic of KA44 showing approach. This approach was used as there were permeable zones (red) and amounts of concerns that a “top-down” approach would open acid introduced to each zone (green). shallow zones and introduce hot inflows which will reduce the effectiveness of the corrosion inhibitors. PK4A All depths are referred to the Casing Head Flange After each zone was acidised, a water overflush was RT-CHF = 5.4m carried out to displace the mud-acid mixture away 24" Casing (ID=0.59m) from the wellbore (Kalfayan, 2008, p73). It should be 23.6m noted that while pumping acid into the well 18-5/8" Casing (ID=0.45m) approximately 2 barrels per minute of water was 119.6m pumped into the well from the side valves to keep the Tie Back = 348.5m 13-3/8" Casing (ID=0.32m) well cool and to prevent acid upflows. Information on 387.8m kick-off point the acidised zones and mixture amounts are shown in 394.3m Figure 5 and Figure 6. Top of 7" liner (ID=0.16m) 9-5/8" (ID=0.22m) Production Casing Shoe 1317.2 mMD/ 1235.4 mVD 1340.6 mMD/ 1256.45 mVD Stage 3 176 bbls HCL 1404 - 1450m 264 bbls HCL:HF Stage 2 586 bbls HCL 1550 - 1700m 879 bbls HCL:HF Stage 1 40 bbls HCL 60 bbls HCL:HF 1870 - 1880m Bottom of 7" liner 1915.2 mMD/ 1710.3 mVD Total Depth = 1922 mMD/ 1715.4 mVD Figure 6: Wellbore schematic of PK4A showing permeable zones (red) and amounts of acid introduced to each zone (green). RESULTS 2 200 1.8 180 Given that multi-rate injection tests along with 1.6 160 1.4 downhole cameras and HTCCs were carried out 140 1.2 before and after the acidising, the well improvements 120 1 100 can be measured reasonably accurately. 0.8 80 [C] Temperature [m/s] Velocity Fluid 0.6 Spinner runs into KA44 (Figure 7) showed that prior 0.4 60 to acidising, the bottom zones were almost fully 0.2 40 blocked and the majority of fluid was exiting at 2090- 0 20 1200 1300 1400 1500 1600 1700 1800 1900 2000 2135mMD. Gross Injectivity index (i.e. without Depth [m] compensating for inflows) at this point had decreased Orig Vel - 90t/h Pre-acid Vel - 116t/h Post-acid Vel - 116t/h to 25 t/h/b. Post-acidising, the spinner profiles were Orig T - 90t/h Pre-acid T - 116 t/h Post-acid T - 116t/h similar to original well conditions suggesting the Figure 8: PK4A PTS profiles comparing original bottom zones had recovered most of its original performance to pre and post acid performance. Gross injectivity index post-acidising performance had doubled to 50 t/h/b. In order to further analyse the improvements due to 1.4 150 acidising, a zone by zone injectivity index (Table 2 1.2 130 and Table 3) was calculated.