40 th Gas-Lift Workshop Houston, Texas, USA Oct. 23 27, 2017 Surfactant-Assisted Gas Lift Pilot Michael Romer and Andrey Troshko ExxonMobil Upstream Research Company Camila Bastidas, Brandon Woods, and Tony Hord ExxonMobil Production Company Shane Rorex, Gee Williams, Matt Gibbens, and Rob Pollack Multi-Chem Brandon Curkan C-FER Technologies
Outline Background Concept Lab Testing Preparation Candidates Selection and Info CFD Predictions Pilot Injection Layout Results and Performance Learnings Summary Oct. 23 27, 2017 2017 Gas-Lift Workshop 2
Surfactant-Assisted GL Concept Physical Principle Liquid column weight in gas lift (GL) wells depends on gas injection rate and gas bubble size population Larger bubbles rise faster, contributing less to weight reduction Smaller bubbles rise slower, contributing more to weight reduction Method Maximizing the population of smaller bubbles will maximize the GL effect Specially formulated surfactants were chosen to promote small bubbles Ideally, foam is not formed; the surfactant concentration is limited to avoid foaming Oct. 23 27, 2017 2017 Gas-Lift Workshop 3
Surfactant-Assisted GL Concept How it Works Option 1: Surfactant disperses lift gas; delays small bubbles from agglomerating into larger, faster ones as the mixture travels to the surface Option 2: Surfactant creates a weak oil in water emulsion with a single effective viscosity value between that of water and oil Both options reduce the slip between gas and liquids, bringing their superficial velocities closer The result is higher average gas holdup the cross-section of the pipe can hold more lift gas Higher average holdup reduces the production pressure gradient A smaller gradient means more drawdown (and production) with the same amount of lift gas Benefit Higher production at the same GL injection rate The same production at a lower injection rate Oct. 23 27, 2017 2017 Gas-Lift Workshop 4
Background SPE 21639 (1991) described a surfactant-assisted GL trial Univ. of Michigan led a lab and field study No follow-up work was found Tested on 3 wells in Siberia and Ukraine 2-7/8 tubing and 5-3/4 casing Water cuts 40 60% < 400 bfpd production without surfactant Unidentified surfactant at 0.3% wt Chemical was delivered via the GL gas All 3 wells showed a production increase Shell presented promising surfactant-assisted GL results at the 2016 ALRDC GL Workshop for capillary line and batch treatments Tables from SPE 21639 Oct. 23 27, 2017 2017 Gas-Lift Workshop 5
Laboratory Testing URC conducted testing at C-FER to validate the concept Repurposed an idle flow loop Added 1% by vol. surfactant (alcohol) to air/water loop to increase holdup (Option 1) Tests at 900 3600 bfpd showed ~10% pressure gradient decrease Videos: 300 m 3 /d, 113 kgpm (5.7 kcfd) GL gas, base case on left, alcohol on right Oct. 23 27, 2017 2017 Gas-Lift Workshop 6
Preliminary Chemical Testing URC and Multi-Chem worked to develop a downhole solution Creation of oil-in-water emulsion recommended (Option 2) Tested primary options with Permian crude at 75% WC to prove concept Chemical #2 had the most effect in gas column testing with methane Emulsion Tendency Testing Oct. 23 27, 2017 2017 Gas-Lift Workshop 7
MC-280 Selection Identified Gulf of Mexico MC-280 Lena as candidate No injection lines, chemical would be injected with the GL gas common with brownfield assets Prod. rates were order of magnitude less than those tested in lab Chemical delivery mode, WC, and prod. rates similar to Michigan study MC-280 wells soon to be plugged & abandoned reduced Pilot risk Production Optimization Technician could be dedicated to Pilot Lena Brochure from KBR Website https://www.kbr.com/documents/project%20profiles/projectprofile_lenacompliantguyedtower.pdf Oct. 23 27, 2017 2017 Gas-Lift Workshop 8
What Makes a Good Candidate Well? The goal of adding surfactant is to reduce slip, further decreasing the column s average density So there s a bigger benefit in wells that have Relatively lower production and/or deeper injection results in longer distance (and duration) to reduce overall slip Heavier columns e.g., higher WC, lower TGLR Higher productivity index (PI) more production with a given drawdown Oct. 23 27, 2017 2017 Gas-Lift Workshop 9
Chemical Testing and Candidate Wells Tested fluids from 7 wells with various surfactants 140 and 200 F to simulate downhole and compressor discharge conditions at various WC 5 of 7 tests resulted in appreciable foam volume increase Unstable (temporary) emulsion; would not expect facilities issue Water-based product chosen to reduce chance of GL gas gunking Selected two wells as primary candidates Higher WCs and several 100 bfpd production Largest PIs and GL injection rates Expected to be lifting from a single point, no reduced-id packoffs Minimal paraffin production, no well work planned Oct. 23 27, 2017 2017 Gas-Lift Workshop 10
Well 1 Info Well 1 (50:50 Oil to Water) Treated Untreated
Well 2 Info
Flow Flow CFD Chemical Delivery Predictions Atomizer can create 10 300 µm droplets, likely smaller end for lower-density surfactant Droplets will have to travel through at least one 90 bend to the well Fewer bends are better as droplets will be lost to wall film at each one only 7% pass Chemical entering the annulus will be a mixture of droplets and film Remaining droplets < 10 µm could travel with the GL gas (~4 hr to GL valve from CO2 Tracing) Droplets would have no issue entering the GL mandrel Flow 2017 Gas-Lift Workshop 13
CFD Chemical Delivery Predictions Remaining droplets >10 µm likely to impact walls and travel as film (~2 days to GL valve at 1 cm/s) Only ~5% of total film expected to make it into the production tubing A liquid level close to the injection point and nearby passage of the GL gas could promote splashing of the chemical into a GL mandrel Surfactant (9ppg) must be lighter than annular fluid Both conditions met with Well 2, neither with Well 1 Oct. 23 27, 2017 2017 Gas-Lift Workshop 14
Injection Layout Drill Deck Two 90 Turns Chemical Tote PSV Check Valve Cellar Deck One 90 Turn Injection Pump Check Valve Wellhead Atomizer Sight Glass Atomizer Well 1 Well 2
Tubing Pressure (psi) Casing Pressure (psi) Early Observations Samples captured at surface ~4 hr from injection initiation Showed some evidence of foaming but was it from chemical? Sampling challenging; manual samples every 5 min. over 2 hr, inconsistent Well 2 slugging Casing pressure increased upon injection; likely foaming wet GL gas Induced injection pressure fluctuations made GL rate maintenance difficult tubing Well 2 casing
Well 2 Injection Injection performance Started with 2000 ppm injection to load the annulus Decremented the injection rate based on well testing results Samples sent to shore for residuals testing; full results not available until pilot completion Measurable chemical residuals were discovered 4 days after injection initiation < 5% of the injected chemical made it into the produced fluids Oct. 23 27, 2017 2017 Gas-Lift Workshop 17
Well 2 Results Production performance Good correlation between residual presence and uplift once chemical took effect 1 2 residual samples analyzed for each day, so active ppm reported may not be fully representative Total fluids uplift ~10-15% WC relatively stable throughout the pilot Further correlation between uplift and chemical presence when TGLR considered Oct. 23 27, 2017 2017 Gas-Lift Workshop 18
Well 1 Injection and Results Injection performance Well 1 followed the same injection schedule as Well 2 No chemical residuals were found in samples Prod. did not increase above base rate Average WC during testing was ~60% vs. ~45% pre-trial WC determined with visual shake-out tests, as test separator was two-phase Well returned to normal when testing ended Oct. 23 27, 2017 2017 Gas-Lift Workshop 19
Well 1 vs. Well 2 Parameter Well 1 Well 2 Successful Delivery? No Somewhat, < 5% Uplift? No Yes, 10 15% Annular Fluid Level Far from Inj. Point Near Inj. Point Chemical Relation to Annular Fluid Heavier, Sinks Lighter, Floats 90 Bends b/w Inj. and Wellhead Two One Near Injection Pressure Limit? Yes No Baseline Water Cut 45% 65% GL Injection Rate 480 kcfd 880 kcfd GL Injection Depth 5750 ft-md 6000 ft-md Baseline Flow Rate 430 bfpd 300 bfpd
Learnings: Preparation 1. Collect annular fluid levels and compare to expected injection depth - Explore fluid addition to raise liquid level up to the inj. point if needed 2. Check fluids compatibility at GL temperature and test annular foaming tendency in advance - Oil-based chemical may reduce GL gas foaming; gunking should not occur with wet GL gas 3. Perform multiple walkthroughs (1 2) to identify equipment locations/procedures 4. Consider well operating conditions during candidate selection (e.g., is the well near injection pressure/rate limits?). Ensure baseline data is representative of typical conditions 5. CFD can help identify deliverability concerns and could improve candidate selection Oct. 23 27, 2017 2017 Gas-Lift Workshop 21
Learnings: Operational 1. As predicted, it is difficult to effectively deliver chemical via GL gas - A several-days delay between injection and effect can be expected 2. Explore options for onsite residuals analysis - Would be tough to optimize injection dosage with feedback delays 3. Dedicate adequate time/resources to data collection (visual/physical fluid samples, temperature/pressure readings, well tests, etc.) 4. Establish injection point as close as possible to wellhead; reduce/eliminate bends downstream. Droplets < 10 µm are important; use an atomizer or better injection method 5. Onsite team/vendor support and frequent team meetings were key 6. If inj. through GL, allow system to stabilize > 2 days before changing GL rate Oct. 23 27, 2017 2017 Gas-Lift Workshop 22
Summary Surfactant-assisted GL concept was identified Objective: Improve efficiency by reducing gas/liquid slip Two options: 1) Disperse lift gas, 2) Create weak oil-in-water emulsion Option 1 validated with air/water flow loop testing Piloted Option 2 surfactant on two wells at for two weeks Injected surfactant with atomizers into GL gas lines near WH Predicted chemical delivery performance with CFD, < 5% delivery expected Evaluated performance with well tests and residuals analysis No chemical reached Well 1 tubing, wet GL gas foaming Less than 5% active chemical delivered to Well 2; but total fluids uplift of 10 15% Surfactant Testing in the Lab (above) and Field (below) Oct. 23 27, 2017 2017 Gas-Lift Workshop 23
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