Light Well Intervention Snøhvit
Well 7121/4-F-2 H
Results & evaluation
Distr List :
VP Operation DPN ON SNO Øivind Nilsen
Leader SSO STN SM3 Dan Pedersen
Principal Engineer Upst Syst Design ECC SE PDBS Morten Svenning
Leader Operation DPN ON SNO Arvid Olsen
Manager Operation ON OMT SNO Lena Skogly
VP Reservoir OW MOD GF Øystein Bøe
VP Petroleum Technology TEX PTEC GGP Tina Todnem Chef Production Engineer TPD TEX PTEC Atle Nordgaard Chef Researcher Reservoir TPD RD IRE Lars Høier
Leader Prod Tech PTEC PT PSC Kjell Lejon
Leader Res Tech Res Mgmt PTEC RT RMAN Sigurd Haugen Specialist Geology PTEC GGP GRC Atle Brensdal
Leading Advisor PTEC RT RMS Vidar Haugse
Specialist Drill Tech DWT DT RM Jamie Andrews Vice President New Energy MPR RE CNO Kai B Lima
Manager New Energy RE CNO CPR Kari Gro Johanson
Specialist RD NEH CST Ola Eiken
Leader Geology RD NEH CST Philip Ringrose
Leader Geophysics RD NEH CST Olav R Hansen
Leader D&W Tech DWS WISS PIV Svein Helge Gundersen Sr Cons Adm Services TPD HR SAB Julien Moisan
Prin Eng Res Tech PTEC RT RMS Nasrin Hashemi
Engineer DWS WISS PIV Stian Bærheim
Princ Geologist Geology ON SNO PTEC Lone Dyrmose Christensen
Sr Engineer ON SNO PTEC Camilla Bådsvik
Engineer Res Tech ON SNO PTEC Douglas Gilding
Geologist Geology ON SNO PTEC Gard Ole Wærum
Specialist Geophysics ON SNO PTEC Bård Osdal
Sr Engineer Res Tech ON SNO PTEC Raquel R. Gonzale Sr Engineer Prod Tech ON SNO PTEC Ann-Kathrin Prestbakmo Leading Advisor Res Tech PTEC RT IOR Trygve Maldal
Leading Eng Prod Tech PTEC PT PSC Anne Marie Lambertsen Sr Engineer Operation Process SNO PROD SUP Sven Ørjan Mannsverk
Table of contents
1 Summary...6
2 Background ...7
3 Operation ...10
3.1 Tag HUD - WL Run # 4 (4.4.2011 22:30 – 5.4.2011 20:00)...10
3.2 PLT and Shut in test - WL Run 5 (5.4.2011 20:00 – 8.4.2011 11:00) ...11
3.3 Tubåen perforations – WL Run# 6-8 (8.4.2011 11:00 – 12.4.2011 15:00) ...13
3.4 Injection test Tubåen...15
3.5 Stø perforations – WL Run # 12-15 (18.4.2011 15:00 – 22.4.2011 16:30) ...16
3.6 Increasing injectivity – Formation fracturing...21
4 Stø reservoir pressure estimation – Reference depth 2460 m TVD MSL...23
5 Conclusion...27
6 References...28
Appendix A – Time planner...29
Appendix B – Tool strings PLT & Perforations...30
List of figures
Figure 2-1 Snøhvit CO2 injector well 7121/4-F-2 H...7
Figure 2-2 Map- and cross sectional view of the Snøhvit reservoir ...8
Figure 2-3 Historical and predicted Tubåen reservoir pressure (Depth 2632.5 m TVD MSL). ...9
Figure 3-1 Results from bailer run ...10
Figure 3-2 PLT Shut in passes analysis ...11
Figure 3-3 PLT Flowing passes analysis ...12
Figure 3-4 Tubåen perforation zones...13
Figure 3-5 Pressure and temperature at WL gauge at 1st Tubåen perforation ...14
Figure 3-6 Pressure and temperature at WL gauge at 2nd Tubåen perforation...14
Figure 3-7 Pressure and temperature at WL gauge at 3rd Tubåen perforation ...15
Figure 3-8 Comparison of Fall-off tests before and after Tubåen perforation...15
Figure 3-9 Sketch of HEX plug ...17
Figure 3-10 Stø perforation zones. ...18
Figure 3-11 Pressure and temperature at well down hole gauge at 1st Stø perforation...19
Figure 3-12 Pressure and temperature at WL gauge at 2nd Stø perforation ...19
Figure 3-13 Bleeding of well pressure before last Stø perforation...20
Figure 3-14 Pressure and temperature at WL gauge at 3rd Stø perforation...20
Figure 3-15 Pressure and temperature at WL gauge during MEG injection from Island wellserver ....21
Figure 3-16 Pressure at wellhead gauge and well down hole gauge during MEG injection from Island wellserver and Melkøya...22
Figure 3-17 CO2 Injection rate and well pressures during start of injection ...22
Figure 4-1 Bleeding of well pressure before last Stø perforation...23
Figure 4-2 Gauge pressures before 2nd Stø perforation...24
Figure 4-3 Gauge pressures after 3rd Stø perforation ...24
Figure 4-4 Well fluid density derived from WL down log after 2nd Stø perforation ...25
Figure 4-5 Well fluid density derived from WL down log after 3rd Stø perforation...26
Figure 4-6 Stø reservoir pressure calculations ...27
1 Summary
To regain injection potential in the Snøhvit CO2 injection well, a Light Well Intervention (LWI) was planned for. The LWI was performed March to April 2011 using the vessel Island
Wellserver. The main objective for the intervention was for the well to get access to a larger volume and thereby increase the CO2 storage capacity. To achieve this the intention was to:
1. Tag HUD to see if debris in well could be an issue for the CO2 injection.
2. Run Production Logging Tool (PLT).
3. Based on PLT, reperforate existing Tubåen intervals.
4. Perforate upper zones in Tubåen.
5. Perform a CO2 Injection test.
6. If injection test did not meet criteria, set plugs in bottom Nordmela between Stø and Tubåen, and perforate Stø,
Tagging of HUD showed no evidence of debris in the well. Based on PLT reperforation of existing intervals was evaluated not necessary. After perforating the two uppermost zones of Tubåen negligible difference in injectivity was observed. In a work meeting with the partners it was decided to plug back Tubåen and initiate the option of perforating Stø.
After perforating the available zones in Stø in 3 runs, injectivity was still not satisfactory. Some injectivity was gained by pressurising the formation with MEG from both Island Wellserver and Melkøya. Satisfactory injectivity was not achieved untill after the intervention while pressurising the formation with CO2 from Melkøya.
Before the last perforation run in Stø, pressure in the well was bled down. The intention was to do the last perforation in underbalance. This was not achievable as the well started to produce while lowering the pressure. A pressure point representing the Stø reservoir pressure was however measured. Stø reservoir pressure was estimated to be 256 +/- 1.5 bars at a reference depth of 2460 m TVD MSL. Initial reservoir pressure at this location was ~272 bars.
Injectivity was re-established after shortly exceeding the reservoir fracturing pressure. The shut in bottom hole pressure at start of RS2011 however was ~320 bars, about ~65 bars higher than the measured Stø reservoir pressure. This has to be investigated.
2 Background
Figure 2-1 Snøhvit CO2 injector well 7121/4-F-2 H
The Snøhvit CO
2injection well was drilled and completed in 2005. A sketch of the well is given
in
Figure 2-1. The well has a minimum inner diameter of 3.875”. The reason for this small inner
diameter was problems during completion [4]. The original plan was for the well to be completed
with 7” nominal bore from HXT to TD. This plan had to be abandoned due to the unfortunate
incident when the production packer went stuck in the production casing. The string had to be
released/cut with a radial torch cutter run on WL. Furthermore the packer milling job yielded
another unfavourable situation. The milling string parted and the mill worked its way through the
production casing. A massive casing leak could be observed at approx 90 bars applied
pressure. The casing was repaired with a Weatherford metal skin casing patch, but a slim hole completion was needed for passing the patch restriction afterwards. Hence the lower part of the completion is configured with a 4 ½” tubing with the production packer set inside the 7” liner.
DHPT gauges were set in the 7” tubing section which was 550 m shallower than expected and ~ 836m TVD above initial top perforation in Tubåen. The well was perforated in November 2005 [1]. Due to observed injectivity problems it was perforated again in 2006 [2]. The primary
objective of the well 7121/4-F-2 H was to serve as disposal for CO
2in the Tubåen formation for the entire lifespan of the Snøhvit Project.
Snøhvit CO
2injection started April 2008. CO
2from the produced gas is being stripped of in an amin process at Melkøya and reinjected into the water filled Tubåen formation. The Tubåen formation is located bellow the ~100 m thick shaly low permeable Nordmela formation (Figure 2-2). The Nordmela formation separates the Tubåen reservoir from Snøhvit’s gas bearing Stø reservoir.
Figure 2-2 Map- and cross sectional view of the Snøhvit reservoir
Injection pressure in the Snøhvit injection well has built up much faster than expected. By start of 2011 the reservoir fracturing pressure was predicted to be exceeded during 4
thquarter of 2011 if no remedial action was taken (
Figure 2-3). An LWI operation was therefore planned for.
The main objective for the operation was to get access to more CO
2storage volume. To achieve this a program with the following bullet points was decided [3]:
1. Tag HUD to see if debris in well could be an issue for the CO2 injection.
2. Run PLT.
3. Based on PLT, reperforate existing Tubåen intervals.
4. Perforate upper zones in Tubåen.
5. Run a CO2 Injection test.
6. Based on injection test, set plugs in Nordmela between Stø and Tubåen and perforate Stø.
Figure 2-3 Historical and predicted Tubåen reservoir pressure (Depth 2632.5 m TVD MSL).
3 Operation
An overview with timing of different steps performed during the LWI can found in appendix A
3.1 Tag HUD - WL Run # 4 (4.4.2011 22:30 – 5.4.2011 20:00)
To control the hold up depth of the well and to check for debris at the bottom a bailer was run.
Negligible amounts of debris were found and HUD was tagged at 2793.4 m MD RKB (Polar Pioner). This was 1.4m deeper than the expected 2792 m MD RKB reported from completion [4]
Figure 3-1 Results from bailer run
3.2 PLT and Shut in test - WL Run 5 (5.4.2011 20:00 – 8.4.2011 11:00)
To check the existing perforations the LWI program included a PLT. First shut-in logging passes were run and then flowing passes. A sketch of the PLT tool can be found int Appedix B.
Analysis of PLT shut-in passes indicated cross-flow from the lowest perforation interval and into the two intervals above. Distribution was ~2 tonnes/hour out of the bottom perforation, ~1.5 tonnes/hour into the middle perforation and 0.5 tonnes/hour into the upper perforation (Figure 3-2).
Figure 3-2 PLT Shut in passes analysis
PLT flowing passes should preferably be run with different flowing rates. Melkøya however has no option to regulate and control the CO2 injection stream directly. The amount of CO2 injected is directly related to production rate. Because of this the Flowing passes were run at only one rate measured to be ~78 tonnes/hr. Analysis indicated flow distributions of about 81% into the bottom perforation, 9% into the middle perforation and 10% into the uppermost perforation (Figure 3-3). As this was in range of expectation based on perforation lengths and reservoir permeability it was decided not to reperforate existing Tubåen perforation intervals.
Figure 3-3 PLT Flowing passes analysis
After completion of the PLT flowing passes the tool was placed with pressure and temperature gauges at a depth of 2780 and a 13 hour long shut in test was performed. A quick interpretation of the shut in data indicated high skin of ~50 and parallel barriers ~100 m from the well. This matches well with earlier interpretations from seismic [6].
3.3 Tubåen perforations – WL Run# 6-8 (8.4.2011 11:00 – 12.4.2011 15:00)
Figure 3-4 Tubåen perforation zones.
Perforation of the two upper unperforated zones of Tubåen was performed in 3 WL runs. The first zone to be perforated was upper parts of Tubåen 3. This zone is from 2719.5 m MD RKB (2624.6 m TVD RKB/2612.8 m TVD MSL) to 2732.0 m MD RKB (2635.8 m TVD RKB/2612.8 m TVD MSL). As the length of the gun string was ~12 meters we were able to perforate this zone in one WL run. The second zone to be perforated was Tubåen 4.2 which is located at the top of Tubåen. This zone is from 2678.4 m MD RKB (2587.8 m TVD RKB/2564.9 m TVD MSL) to 2701.5 m MD RKB (2608.4 m TVD RKB/2585.4 m TVD MSL). Due to length this zone had to be perforated in two WL runs. A sketch of the perforation tool can be found in appendix B.
Pressure and temperature measured at WL gauge during perforations are plotted in Figure 3-5, Figure 3-6 and Figure 3-7. As can be seen the achieved injectivity was limited with hardly any pressure drop observed. The temperature increase is believed to be caused by added heat from firing the guns. The temperature increase is less at the 3rd perforation than at the two previous
ones. This is most likely due to MEG in the well. After the two first perforations MEG/water (90/10) from Melkøya was injected into the well to prevent blocking of pores due to salt precipitation caused by dry CO2 meeting formation water.
Figure 3-5 Pressure and temperature at WL gauge at 1st Tubåen perforation
Figure 3-6 Pressure and temperature at WL gauge at 2nd Tubåen perforation
Figure 3-7 Pressure and temperature at WL gauge at 3rd Tubåen perforation
3.4 Injection test Tubåen
After the last perforation in Tubåen an injection test was initiated. The intention was to check whether the new perforations had increased the CO2 storage potential or not. During this test the P&T sensor on the WL tool was placed at a depth of 2754 m MD RKB and 3 short fall-off test were run. Comparison between these fall-tests and similar tests done weekly before the intervention indicated a small increase in injectivity. Additionally the injectivity improved from 11.4 on the first test, 13.1 on the second test to 14.6 on the last test. This indicates that the new perforations where in contact with the reservoir.
The injection test was ended with a shut-in test. This test lasted for approximately 8 hours. A comparison between this test and the shut in test done before perforation is given in Figure 3-8
Figure 3-8 Comparison of Fall-off tests before and after Tubåen perforation
The criteria for abandoning Tubåen and perforating the Stø formation had been discussed and documented before start of the intervention [5]. According to this Tubåen would be abandoned if perforations gave less than 5 bars drop in reservoir pressure. As can be seen from Figure 3-8 the pressure drop was ~2 bars. Based on this it was decided to go for the option to plug back Tubåen and perforate the Stø formation. It was concluded that the probable reason for not achieving a satisfactory injection potential was that the new perforation zones were in contact with bottom Tubåen and already pressurized by CO2 injection in the lower zones.
Tubåen was abandoned due to only marginal injection potential increase after adding perforations. Based on observations of bad injectivity, also after perforating Stø, we can however not conclude that all zones of Tubåen are pressurized. A clean-up of the well would have been desirable but very challenging due to CO2 and the restriction in the well.
3.5 Stø perforations – WL Run # 12-15 (18.4.2011 15:00 – 22.4.2011 16:30)
Before perforation of Stø connection to Tubåen had to be eliminated. Two specially designed HEX plugs were set at depths 2673 m MD RKB and 2663 m MD RKB. These depths
correspond to bottom parts of Nordmela. To prevent the plugs from moving upwards a gauge hanger was set on top of the plugs.
Figure 3-9 Sketch of HEX plug
Figure 3-10 Stø perforation zones.
According to the initial program only Stø 1 and bottom part of Stø 2 were to be perforated. The idea was to keep the CO2 bellow a barrier observed on the CPI log (Figure 3-10). This was considered an extra safety barrier separating the injected CO2 from the produced gas. As only marginal injectivity was achieved after perforating the planned zones it was however decided to also perforate the upper part of Stø 2. The initial zone to be perforated, corresponding to Stø 1 and bottom part of Stø 2, was from 2553.6 m MD RKB (2476.7 m TVD RKB/2453.7 m TVD MSL) to 2582.3 m MD RKB (2502.3 m TVD RKB/2479.3 m TVD MSL). The additional part corresponding to upper Stø 2 was from 2539.2 m MD RKB (2463.8 m TVD RKB/2440.8 m TVD MSL) to 2552.6 m MD RKB (2475.8 m TVD RKB/2452.8 m TVD MSL). Stø was perforated in 4 WL runs, including one miss-run in which the guns would not fire. The first perforation length was shot using a tool string including ~16 meters of guns and no P&T gauge. The next
perforations were shot using a tool string similar to the one used during Tubåen perforations. A sketch of the tool strings can be found in Appendix B.
Pressure and temperature measured during the two first Stø perforations are plotted in Figure 3-11 and Figure 3-12. The first perforation did not include P&T gauges in the gun string. For this perforation pressure measured at the well down hole gauges are plotted (Figure 3-11). The
plots clearly show effects from the perforations. The well pressure immediately starts dropping but the injectivity is still not satisfactory.
Figure 3-11 Pressure and temperature at well down hole gauge at 1st Stø perforation
Figure 3-12 Pressure and temperature at WL gauge at 2nd Stø perforation
Based on results from the two first perforations in Stø it was decided to try to shoot the last perforation in underbalance. The pressure was reduced by bleeding off the well. However, as the pressure reached ~200 bars on the well down hole gauge, corresponding to ~250 bars at Stø depth, the well started to produce. Productivity seemed to be far better than injectivity.
Because of this we were not able to perforate in underbalance. Results from bleeding off the well and from the last Stø perforation are plotted in Figure 3-13 and Figure 3-14. Injectivity after the last Stø perforation was far from satisfactory. This can be observed from the rapid pressure
increase at the end of the plot in Figure 3-14 which is caused by MEG injection from Island Wellserver.
Bleeding off pressure in Well before 3rd perforation in Stø formation (1823 m MD) (21.04.2011)
180 185 190 195 200 205 210 215 220
20:02:24 20:31:12 21:00:00 21:28:48 21:57:36 22:26:24 22:55:12 23:24:00 23:52:48 Time
Pressure (bar)
46 46.5 47 47.5 48 48.5 49 49.5 50
Temperature (°C)
Gauge Pressure Gauge Temperature
Figure 3-13 Bleeding of well pressure before last Stø perforation
Perforation#6 Upper Stø 2 Formation (2539.6-2552.1m MD) (21.04.2011)
240 250 260 270 280 290 300
22:16 22:23 22:30 22:37 22:45 22:52 22:59 23:06 23:13 23:21
Time
Pressure (bar)
70 72 74 76 78 80 82 84 86 88 90
Temperature (°C)
Down Hole pressure Down Hole Temperature
Figure 3-14 Pressure and temperature at WL gauge at 3rd Stø perforation
3.6 Increasing injectivity – Formation fracturing
As the injectivity after perforating all the available formation zones still was unsatisfactory it was decided to increase well pressure to force fluid into the formation. The reservoir fracture
gradient was exceeded by pumping MEG (50l/min) from Island Wellserver. A maximum well head pressure of 210 bars, corresponding to ~ 412 bars at Stø depth, was achieved. At this point MEG injection was stopped as the allowed pressure limit with the tool string in the well was reached. During injection pressure broke down twice, once at ~ 399 bars and once at ~409 bars, as visualized by the plot in Figure 3-15.
Figure 3-15 Pressure and temperature at WL gauge during MEG injection from Island wellserver
To be able to increase the well pressure even more it was decided to inject MEG from Melkøya in addition to the MEG injected from Island wellserver. MEG/water (90/10) at a rate of 80 l/min from Melkøya was injected in addition to the MEG at 50 l/min from Island Wellserver. Totally 16m3 of MEG was pumped into the well. At a wellhead pressure of 204 bars the maximum capacity from Melkøya was reached. Higher pressure or rate could not be achieved. At this point Island wellserver had no further options and the decision for Island wellserver to end its part of the operation was made.
Figure 3-16 Pressure at wellhead gauge and well down hole gauge during MEG injection from Island wellserver and Melkøya
Melkøya gained control of the injection well 25th April 2011. An attempt to inject CO2 from the static overpressured flowline, which had a pressure of 174 bars upstream choke at wellhead, gave only 2-3 bars pressure drop during a period of more than 12 hours. At 26th April 2011 injection of CO2 from Melkøya was started. A maximum pressure of 204 bars was reached before pressure abruptly broke down. After some pressure oscillations at a high pressure level and constant injection rate of ~60 tonnes/hour, pressure started dropping steadily. The injection rate was increased to its maximum of ~80 tonnes/hour. At shut down due to RS11 29th April 2011 pressure seemed to still be dropping. At this time pressures had reached 130 bars at wellhead and 270 bars at the well down hole gauge, corresponding to ~320 bars at Stø depth.
Figure 3-17 CO2 Injection rate and well pressures during start of injection
4 Stø reservoir pressure estimation – Reference depth 2460 m TVD MSL
Figure 4-1 Bleeding of well pressure before last Stø perforation
As pressure was bleed down before the last Stø perforation we got to a pressure level where the well started to produce. This point represents the Stø reservoir pressure. Due to
discrepancies between the permanent well down hole gauge and the WL gauge there are some uncertainties associated with the actual reservoir pressure. Figure 4-2 and Figure 4-3
demonstrates the discrepancies between the gauges. A WL station log at 1823 m MD RKB before the second perforation measures pressures 3.1 to 3.6 bars lower than the permanent well gauge at this depth. A similar station log after the 3rd Stø perforation measures 3.0 to 3.9 bars lower pressures than the permanent gauge.
Figure 4-2 Gauge pressures before 2nd Stø perforation
Figure 4-3 Gauge pressures after 3rd Stø perforation
The WL gauge used during perforation was of a different type than the one used during the PLT. The gauge from the PLT was a PSP Quartz Gauge with uncertainty range +/-0.1 bars.
This gauge is considered very accurate and comparison between this gauge and the permanent well down hole gauge showed only negligible discrepancies. This indicates that the well down
hole gauge is reliable. Another point indicating that the permanent well down hole gauge is reliable is that it follows the measured wellhead pressure nicely (Figure 4-2). The WL gauge however seems to respond slowly and also appears to be drifting over time.
Schlumberger calibrated the WPPTT 30 tool after the intervention and acknowledge that the tool measured 1.68 bars too low at the intervention. In addition Schlumberger was not able to recreate the measurement after the calibration admitting that the tool is not reliable.
Based the above arguments it is believed that the permanent well down hole gauge is correct.
Pressures measured by the WL gauges therefore have to be corrected.
The WL measurements we have of reservoir pressure are from depths 2425.8 m TVD MSL and 2438.2 m TVD MSL. To be able to estimate pressure at our reference depth of 2460 m TVD MSL we need knowledge of the fluid in the well column.
Figure 4-4 Well fluid density derived from WL down log after 2nd Stø perforation
Figure 4-5 Well fluid density derived from WL down log after 3rd Stø perforation
Figure 4-4 and Figure 4-5 shows derived fluid densities in the well. From these figures we conclude that injected MEG is located at the bottom of the well and bellow our measured WL pressure points. The density of the MEG estimated from the down logs is low compared to expectations. Density calculated based on difference between the two pressure points taken after 2nd and 3rd Stø perforation however gives a density of 1.1 s.g., which seems more likely for MEG. This method requires that well pressure has not changed between the two
measurements. Reasons for the low density estimated from the down logs might be caused by moving tool in addition to a constantly dropping well pressure. As the WL gauge has been confirmed to have issues none of these methods of density calculation can be trusted. A theoretical MEG density will therefore be used for estimating Stø pressure at reference depth.
Figure 4-6 Stø reservoir pressure calculations
Estimation of Stø reservoir pressure at reference depth 2460 m TVD MSL is demonstrated in Figure 4-6. Calculations are performed using our two WL reservoir pressure measurements with both clean and CO2 saturated MEG. As a conclusion Stø reservoir pressure is calculated to be 256 +/- 1.5 bars. Initial reservoir pressure at this location and reference depth was ~272 bars.
5 Conclusion
The well intervention was accomplished according to program. Due to only marginal injection potential gain after adding perforations to Tubåen, two HEX plugs were set in Nordmela and Stø 1 and Stø 2 perforated. During operation Stø reservoir pressure was found to be 255.9 +/- 1.4 bars at a reference depth of 2460 m TVD MSL.
Injectivity was re-established after shortly exceeding the reservoir fracturing pressure. The shut in bottom hole pressure at start of RS2011 however was ~320 bars, about ~65 bars higher than the measured Stø reservoir pressure. This has to be followed up.
6 References
1. Perforering I 7121/4-F-2 H, Offshore rapport, November 2005 2. Summary of remedial work on CO2-injector 7121/4-F-2 H
3. Light Well Intervention Snøhvit Well 7121/4-F-2 H; PLT, Plug and perforation.
4. FINAL WELL REPORT; Final Well Report Completion 7121/4-F-2 H; Licence no: PL099, PL097; Well: NO 7121/4-F-2 H
5. Updated: Status & Master Plan for Snøhvit CO2-injection (October 2010)
6. Technical Achievement 2010 Snøhvit CO2 Storage, Snøhvit CO2 Tubåen Fm. Storage capacity and injection strategy study