The URL can be used to link to this page

Home My WebLink About2022 Nikaitchuq Polymer Pilot Project The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 1 of 10 Nikaitchuq Polymer Pilot Project DISTRIBUTION: AOGCC The following report has been prepared for the AOGCC in partial fulfillment of the conditions of approval of AIO 36.003. The polymer pilot project aimed to evaluate EOR polymer injection in the OA sand reservoir of the Nikaitchuq field. In this document, the results of the polymer pilot in well OP‐I2 are presented in terms of effects on the neighboring producer wells OP12-01 and OP17-02. The study’s results included the effects of the polymer on the neighboring producers, indications about polymer injectivity, and information on polymer front advancement. From an operational point of view, the test pointed out some critical aspects that may arise during polymer injection and provided valuable expertise in case of a future extension of the project. The pilot test results are considered encouraging, with positive effects on the rate of the producers and changes in the trends of the water cut of the monitored wells. The effects observed are relevant considering that the pilot test was not confined: the polymer injection took place in a single well, with the neighboring producers being affected by the presence of other water injectors in the area. Prepared by: Eni Us Operating Co. Inc. (Alaska Reservoir Group) DATE: 02/07/2023 The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 2 of 10 NIKAITCHUQ UNIT- POLYMER PILOT PROJECT INTRODUCTION This document summarizes the results of the polymer injection pilot test for the OA sands reservoir carried out in the OP‐I2 well. Those results are quantified in terms of oil rate & water cut rates observed on the neighboring producer wells OP12-01 and OP17-02. The study aimed to evaluate polymer injection's effects in the Nikaitchuq field's OA sand. The pilot project was conducted on the OP-I2 well (See Figure 1). Polymer injection started on October 22, 2019, it was suspended on March 24th, 2020, due to Covid-19-related issues. The project resumed operations on March 19th, 2021 and was concluded on December 16th, 2022. Polymer Skid on Oliktok Point Drill Site (OPP) The successful execution of this pilot test allowed Eni to gather important information about the effectiveness of polymer injection into the Schrader Bluff OA sands in the Nikaitchuq field. Key results of the study included the effects of polymer injection on the neighboring production wells, indications about polymer injectivity over time and tracer arrival times. These findings provided valuable expertise in developing a case to support a future full-field polymer injection project. The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 3 of 10 Results quantification was done using dynamic modeling and decline curve analysis (DCA). At the end of June 2022, the estimated additional oil recovered associated with the polymer injection was approximately 54,000 stb, corresponding to an average of +120 bopd for the period considered. Figure 1. Nikaitchuq Field Development Map (area of study outlined with red dashed line) SI11-FN6 SI13-FN4 SI14-N6 SI17-SE2 SI19-FN2 SI20-N4 SI25-N2 SI26-NW2 SI29-S2 SI32-W2 SI34-W6 SI35-W4 SP40-E4 SP05-FN7 SP08-N7 SP10-FN5 SP12-SE3 SP16-FN3 SP18-N5 SP21-NW1 SP22-FN1 SP23-N3 SP24-SE1 SP27-N1 SP30-W1 SP31-W7 SP33-W3 SP36-W5 OI06-05 OI07-04 OI11-01 OI13-03 OI15-S4 OI20-07 SI07-SE4 OI24-08 OP-I2 OP03-P05 OP04-07 OP05-06 OP08-04 OP10-09 OP12-01 OP14-S3 OP16-03 OP17-02 SP03-NE2 OP18-08 OP09-S1 SP04-SE5 SP09-E2 SP01-SE7 SP28-NW3 SP42-NE4 SI06-NE1 SI15-E1 SI02-SE6 SP41-E3 SI43-NE3 488000 492000 496000 500000 504000 508000 512000 516000 520000 524000 488000 492000 496000 500000 504000 508000 512000 516000 520000 5240006032000603600060400006044000604800060520006056000606000060640006068000607200060760006080000 6032000603600060400006044000604800060520006056000606000060640006068000607200060760006080000Nikaitchuk Development Date 02/06/2023 Signature Alaska Dev. Team 0 2000 4000 6000 8000ftUS 1:25000 Symbol legend Water OPP outline Converted AK_Federal_Blocks Converted Alaska_North_Slope_Facilities Alaska_Roads_and_Trails Drilled LateraL SI17-SE2 SP23-N3 L1 SPXX-NE4L1 Drilled Lateral SI02-SE6 Drilled Lateral SI06-NE1 Well trace SP05-FN7 L1 Drilled Lateral SP03-NE2 L2 Drilled Lateral SI15-E1 Drilled Lateral SP01-SE7 SP09-E2 L1 SP01-SE7 L1 SP18-N5 L1 Drilled Lateral SP28-NW3 SP28-NW3 L1 Drilled Lateral SI34-W6 SP30-W1L1 SP33-W3L1 Drilled Lateral SP04-SE5 SP10-FN5L1 SP03-NE2 L1 SP16-FN3L1 SP27-N1L1 SP04-SE5L1 Drilled Lateral SI07-SE4 Drilled Lateral SP21-NW1 Drilled Lateral SP01-SE7 Drilled Lateral SI11-FN6 Drilled Lateral SI13-FN4 Drilled Lateral SI14-N6 Drilled Lateral SI19-FN2 Drilled Lateral SI20-N4 Drilled Lateral SI25-N2 Drilled Lateral SI26-NW2 Drilled Lateral SI29-S2 Drilled Lateral SI32-W2 Drilled lateral SI35-W4 Drilled Lateral SP05-FN7 Drilled Lateral SP08-N7 Drilled Lateral SP10-FN5 Drilled Lateral SP12-SE3 Drilled Lateral SP16-FN3 Drilled Lateral SP18-N5 Drilled Lateral SP22-FN1 Drilled Lateral SP23-N3 Drilled Lateral SP24-SE1 Drilled Lateral SP27-N1 Drilled Lateral SP30-W1 Drilled Lateral SP31-W7 Drilled Lateral SP33-W3 Drilled Lateral SP36-W5 Drilled Lateral SI26-NW2 SP36-W5L1 SP08-N7 L1 SP36-W5L1 SP24-SE1 L1 SP21-NW1 L1 SP12-SE3 L1 SP31-W7L1 SP12-SE3 L1 Drilled Well OI06-05 Drilled Well OI07-04 Drilled Well OI11-01 Drilled Well OI13-03 Drilled Well OI15-S4 Drilled Well OI20-07 Drilled Well OI24-08 Drilled Well OP-I2 Drilled Well OP03-P05 Drilled Well OP04-07 Drilled Well OP05-06 Drilled Well OP08-04 Drilled Well OP09-S1 Drilled Well OP10-09 Drilled Well OP12-01 Drilled Well OP16-03 Drilled Well OP14-S3 Drilled Well OP17-02 Drilled Well OP18-08 Well trace OP03-P05 L1 Well trace OP05-06 L1 Well trace OP08-04 L1 Well trace OP09-S1L1 Well trace OP10-09L1 OWC -4160 Well trace OP14-S3 L1 Well trace OP18-08 L1 Well trace OP16-03L1 Well trace OP03-P05 L1 Drilled Lateral SP09-E2 Drilled Lateral SP40-E4 Drilled Lateral SP40-E4 L1 Drilled Lateral SP41-E3 L1 Drilled Lateral SP41-E3 Drilled Lateral SI43-NE3 SPXX-NE4 Well trace SI44-S5 Nikaitchuq Outline OA Top - Faults Pad Spy Island Injection water Oil Proposed Producer Mainbore Producer L1 Injector The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 4 of 10 PILOT POLYMER During the two phases of polymer injection, a particular focus was placed on the effects seen at the two producers well adjacent to the injector: OP12-01 and OP17-02. As the map above illustrates, OP12-01 is parallel to the polymer injector, while OP17-02 productive interval is longer, and approximately 2/3 of the well’s length is influenced by the polymer injector. Because of this, the positive effects of polymer injection were anticipated to be preferentially seen in OP12-01 rather than OP17-02. Another critical factor to be considered in interpreting the pilot test results was the well pattern. The monitored producers can be classified as unconfined with polymer injection in a single well, OP-I2. The results achieved are lower than expected from a confined test. The main parameters monitored in the producers were the oil production rate, the water cut and the tracer arrival. Production Rate - Decline curve analysis (DCA) & Simulation To quantify the polymer pilot’s beneficial effects on producers, a DCA and a Dynamic model simulation were considered, and the results were compared with the observed oil rate values. The results of these predictive tools were compared with the actual data from the field. Then, the oil gain associated with polymer injection was calculated as a difference between the production obtained with polymer injection (observed data) and the production predicted by the two tools in the case of simple water flooding (do nothing case). (See Figures 2 & 3) Figure 2. Pilot Test ‐ OP12-01 Well Oil Rate Analysis (June 2022) The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 5 of 10 Figure 3. Pilot Test ‐ OP17-02 well Oil Rate Analysis (June 2022) As illustrated in the figure above, the DCA curve and the simulated one are almost identical for OP12-01 well. At the same time, DCA is more pessimistic than the simulation for the decline in production of OP17-02 well. During the second phase of polymer injection (from March 2021), a clear increase in oil production rate was tangible in OP12-01 well, especially from February 2022, while the effects on OP‐17 are more limited, as expected, with a stabilization of the oil produced. The positive effects of polymer injection are more visible during the second phase than the first; this can be due to different factors: • Polymer injection period in the first phase may have been too limited (only a few months) • The downtime of the plant in the first phase was probably too high (25% compared to 3% of the second phase), with water bypassing the polymeric solution when injected • The second phase of polymer injection might have benefited from some polymer still present in the reservoir from the previous phase The DCA decline is more pessimistic than the simulation results, leading to a higher oil gain when compared to the actual data observed during polymer injection. Considering the DCA approach (most conservative case), as the reference case, the oil gain attributable to polymer injection was estimated at 54 kstb at the end of June 2022, which, distributed over the period of pilot implementation, results in an average of 120 bpd of additional oil production rate. The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 6 of 10 Water cut When studying the effects of polymer injection, the water cut of the adjacent producer wells is one of the essential variables to be monitored. The WC history of the two monitored wells is illustrated below: Figure 4. OP12-01 well Water Cut Figure 5. OP17-02 well Water Cut The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 7 of 10 The WC results of the OP12-01 and OP17-02 wells are coherent with what was observed in the oil production rates; observations are summarized as follows: • OP12-01 well shows an essential change in the WC trend, stopping the continuous increase seen over the years and leading to a slight but clear reduction in the WC (approximately 4%) during March 2022. • OP17-02 well presents limited effects on the WC, but stabilization is evident since the start of the second phase of polymer injection, with an observable change in the WC trend. Tracer Breakthrough Tracers can be very effective in determining the effects of the polymer injection in the reservoir since they can highlight modifications in the advancement of the injection front. Theoretically, polymer injection should stabilize the injection front, displacing a part of the oil left behind during a simple water flooding; if this happens, the front is more homogeneous and its arrival at the producers is delayed. To see a possible delay in tracer breakthrough due to the presence of polymer, two tracer campaigns were implemented in Nikaitchuq Field: the first one during water flooding and the second one some days after the start of the first phase of the polymer pilot. The results are reported in Figure 6. Figure 6. OP17-02 Tracer arrival time with polymer (days) Figure 7. OP12-01 Tracer arrival time with polymer (days) 0 2 4 6 8 10 12 14 16 18 123456891011122539536710119233241947749450852453855557058559962763066267869170872273876878380081482884285987388990391893495096498199410081026105610731087110411171134T-140A OP17 Tracer Response: Injector -Producers (ppb) T-Conc(ppb)Min Expected T-Conc @ BT 0 1 2 3 4 5 6 7 1 3 4 5 6 8 9 10 11 12 25 39 53 67 100 192 419 538 677 691 722 738 752 768 783 800 814 964 981 994 1008 1026 1056 1073 1087 1104 1117 1134 T-140A OP12 Tracer Response: Injector -Producers (ppb) T-Conc(ppb)Min Expected T-Conc @ BT The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 8 of 10 OP17-02 OP12-01 Tracer Arrival with Water Flood (days) 434 574 Tracer Arrival with Polymer Flood (days) 550-570 722-738 Figure 8. Tracer Arrival (days) The analysis of the produced water samples showed a significant delay of tracer arrival with polymer in the wells compared to the arrival time with water. To determine the presence of polymer in the produced water, flocculation tests carried out on the producers show the arrival of polymer only at OP17-02. The lab analysis showed that the polymer concentrations were still below detection limits and insufficient to determine a clear breakthrough. No positive flocculation test results were obtained at OP12-01 and OP10-09 wells, coherently with the results of the tracer campaign. The main parameters monitored at the polymer injector well OP-I2 tubing Head Pressure, injection rate, and viscosity. The observed results represented proof of a change in the injection front, as expected from polymer theory. Tubing Head Pressure (THP) To evaluate the polymer injectivity, a particular focus was put on the rate of injection (Q) and tubing head pressure (THP) values. Bottom hole pressure data (BHP) can be more representative of downhole conditions, but unfortunately, this well was not completed with a downhole gauge. A retrievable memory gauge was installed and is retrieved approximately every year, so THP is taken as a reference for daily monitoring. As expected, injecting a more viscous fluid leads to an increase in pressure; the first THP limit of 650 psi was reached in the second half of 2021: when a THP limit is reached, the injection rate was cut so that it is no longer possible to maintain the target injection rate of 2,600 bwpd. The THP limit was increased to 750 psi in January 2022, after the extraction of the DH memory gauge in December 2021, and showed that there was still a pressure margin from the fracturing pressure. The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 9 of 10 Figure 9. OP‐I2 THP and Q Viscosity During the pilot test, attention was focused on the viscosity values for the injected polymer solution measured in the field. Figure 10 shows the viscosity maintained during the second phase of the pilot, with average values in the range of 6‐8 cP when injecting at the target concentration of 1,100 ppm. Figure 10. Injected solution Viscosity The present document is Eni US Operating Co property - To be held confidential consistent with AS 38.05.035(a)8 Eni US Operating Co. Inc. Nikaitchuq Polymer Pilot Project Page 10 of 10 Downtime During the second phase of the pilot test, two main periods of well shutdown occurred, each lasting approximately one month. The first was in August 2021 due to a field-wide shutdown for planned production plant maintenance activities. The second one occurred in July 2022, when the skid was removed due to activities related to ConocoPhillips. Outside of these two shutdowns, the polymer injection skid experienced minimal downtime (approximately 3%). CONCLUSIONS AND WAY FORWARD The polymer injection study started in 2016 with the first EOR evaluations. After much work in the following years, it was finally brought to a field application, with an inter‐well polymer pilot test that concluded at the end of 2022. The pilot test allowed us to gather important information about the effectiveness of polymer injection in Nikaitchuq Field (OA sands reservoir). Significant results of this study were the effects of the polymer injection on the neighboring producers, the indications about polymer injectivity, and the delay in the tracer’s arrival at the producers. Moreover, from an operational point of view, the test pointed out many criticalities that may arise during polymer injection, providing valuable expertise in case of a future project extension. The pilot test results are considered encouraging, with positive effects on the oil production rate of the producer wells and a clear change in the trend of the water cut for the same wells. The results observed are relevant considering that the pilot test was not confined: the polymer injection took place in a single well, with the neighboring producers being affected by the presence of other water injectors in the area. These results were quantified using a dynamic model and decline curve analysis (DCA). The estimated additional oil recovered associated with polymer injection is approximately 54,000 stb, corresponding to an average of +120 bopd in the period considered. Finally, the delay in tracer breakthrough experienced during polymer injection highlights a modification of the injection front that becomes more stable and uniform, in line with polymer injection theory. A comprehensive work on polymer injection modeling was performed, and dynamic simulations were run to study different strategies for an extension of polymer injection at the full‐field level. Positive results in terms of oil recovery emerged in all the forecast scenarios analyzed: considering a full field polymer injection simulation for a period of 10‐ 15 years, the additional oil recovery compared to a water flooding case is estimated to be in the order of 30 – 40 MMstb, with a + 4 – 5 % of RF. Currently, a pre‐feasibility study for the full field implementation of this EOR technique is underway and has shown no significant impediments or critical showstoppers.