#	Project Name	Injectivity	Viscosity Stability	Economic Notes	Operational Issues
1	Aishwariya Lower Fatehgarh	Full-field ramp to 40–50 kB/D within one month; 25–30-cP wellhead viscosity	Serious produced-HPAM over-hydrolysis and precipitation documented	Shared Mangala polymer facility via ~14 km pipeline	ESP failures, strainer/PWRI fouling, pipeline pressure and increased pigging; calcium-carboxylate deposits
2	Alaska North Slope (Milne Point)	Short-term injectivity comparable to water; long-term injectivity declines as polymer fills reservoir	Target 45 cP maintained initially; effective viscosity reduced in situ by dilution with injected water	economic evaluation not yet reported	Declining injectivity over time; polymer slicing unit downtime; gas in source water; need to inject near fracture pressure
3	Baytex 14-50-25W3	Good injectivity; max WHIP ~5000 kPa reached at 50 cP	Very stable; minimal degradation, produced viscosity up to 95% of injected, typically stabilizes at 10–30%	Polymer flood OPEX ≈ 2× waterflood; polymer ≈ 70% of incremental cost; considered economic success	Channeling, high WOR spikes, max injection pressure limits; required gel conformance treatments
4	Bhagyam	Field challenges reported, but deployment achieved		Full-field deployment selected after successful pilot	Early water breakthrough; injectivity, conformance, surface and model-history-match challenges
5	Bohai Bay Block-X/SZ36-1	Average injection pressure rose 7.2 → 8.9 MPa, ~24%	Long-term field propagation demonstrated; associative polymer selected because conventional HPAM weakened under high salinity/hardness	~4.8 million m3 incremental oil from 99,183 t cumulative polymer; unit economics not reported	Platform-space limits; pressure rise; polymer/reservoir compatibility; scaling and produced water reinjection risks [ythx.scu.edu.cn]
6	Canto de Amarao
7	Captain EOR	Repeated field responses; six new subsea injectors in Stage 2	Offshore design includes polymer handling and non-shearing equipment	Enabled otherwise negative-NPV infill C64; improved oil rate and reduced water handling	Polymer manufacture, shipping/storage, back-produced polymer management, topside/subsea complexity
8	Chengdao 22F	~32,000 B/D; 90–130 barg WHP; >98% injection system reliability	Non-shearing choke valves and shortened maturation used to preserve viscosity	Powder selected despite higher CAPEX to reduce transport and OPEX; ~12 t/d polymer	Footprint, logistics, maturation, mechanical degradation and produced water treatment
9	Chichimene Fm1	Repressurization and WOR control observed	Numeric viscosity retention NR	Lower energy/carbon intensity evaluated against baseline	350–700-cP oil, broad permeability range, large thickness and pattern-scale variability
10	Courtenay/Châteaurenard	~380 m3/d during commercial injection	Injected viscosity ~21 cP; produced polymer characterization found no degradation	Additional 265,000 bbl reported at ~$12/bbl total cost; operation described as profitable	Produced polymer lagged simulation; pressure support and oil bank attribution required careful interpretation
11	Daqing (CNPC)	Very good; sustained over decades	Stable due to moderate T and salinity	Largest polymer flood globally	None major; well-developed operations
12	Diadema (CAPSA)	—	—	—	—
13	Diadema Pilot	Good; maintained even at 3000 ppm	Stable; viscosity ↑ where Fe2+ low	Strong oil rate gain; water cut ↓ 97.5% → 83%	Water quality critical; channeling; injection unbalance
14	East Bodo	Increased injection pressure and breakthrough observed	Target viscosity difficult to maintain because of water quality	Pilot intended to test commercial fieldwide reserve capture	Water quality, viscosity target, polymer breakthrough, bottom water and gas cap
15	East-Messoyakhskoye	Good; stable injection without near-wellbore plugging up to ~78 atm	Stable under Arctic conditions; no significant mechanical or chemical degradation observed	NPV ≈ 125.4 million RUB; PI = 1.40; ~43 t oil per t polymer	High water quality requirements; uncertainty in fracture pressure; optimal viscosity for full-field not yet defined
16	El Corcobo Norte	Injectivity loss reported, and pressure limit of 4700 kPa was achieved	achieved with no major operational issue		No major problems with Polymer plant operation and water–oil separation
17	EPIC001 Offshore Heavy oil	Injectivity loss increases with shear-rate modeling	Viscosity improves recovery but increases computational cost	Better economics at low adsorption; high adsorption kills NPV	Adsorption and shear impact injectivity and economics
18	Greater Burgan Wara East	Good	Stable (≈5 cP)	Positive NPV	None critical
19	Greater Burgan Wara PF North	Good	Stable (≈3.6–5 cP)	Economically favorable	Injectivity fluctuations managed
20	Greater Burgan Wara West	Good	Stable (≈7 cP)	Strong economics	RRF increased locally
21	HTHS Carbonate-Injectivity Test 1	Injectivity index declined from ~8 to ~0.8 B/D/psi; no fracture contribution	Stable under HTHS; additional 10–20% in situ viscosity loss inferred	Economics not evaluated; technology derisking phase	Initial skin buildup linked to water quality; shear-thickening risk at high rates; injectivity decline with polymer bank growth
22	HTHS Carbonate-Injectivity Test 2	Injectivity index declined from ~10 to ~0.9 B/D/psi; stable injection without fractures	Stable; viscosity control within ±10% of target; no shear-thickening observed	Economics not evaluated; supports future SIMGAP/SIWAP pilots	| Improved water quality mitigated injectivity impairment; no polymer-induced damage
23	JZ9-3 Polymer/SP Flood	8 injectors/23 producers in full-field SP stage		Oil rate doubling and water-cut reductions reported in responsive wells	Offshore chemical logistics; only 11 of 23 producers showed obvious response
24	Kalamkas Full-Field	No injectivity loss in pilots; injectivity comparable to waterflood; fractures aid injectivity	High when using PSU units; minimal degradation with oxygen control; severe viscosity loss observed with eductor units	NPV ≈ USD 695 million; PI ≈ 1.6; OPEX savings ≈ USD 34.7 million from reduced water handling; water savings ≈ 60 MMbbl	Large mobility contrast challenges. High salinity and iron in brine; oxygen-induced polymer degradation; eductor units caused up to ~45% viscosity loss; need strict QA/QC and nitrogen blanketing
25	Mangala Field	Good injectivity; horizontal well design	Stable under field conditions	Strong economics; major Indian PF success story. World’s largest polymer flood	Water cut management; need polymer quality control
26	Marmul	Good; sustained long-term injectivity achieved	Stable under high T and salinity; SAV10 formulation specifically engineered for HTHS conditions	Polynomial slug optimization: 0.5–0.7 PV saves 26–36% polymer	None major; long-term reservoir temperature requires advanced polymer stabilization
27	Matzen Field 8TH	Good injectivity. In some cases, injectivity improved by biocide treatment (~15% gain)	Polymer degradation ~20% in situ (stability moderate)		Past activities reported polymer degradation and microbial activity before biocide
28	Mauddud DRCC	Good	High thermal and chemical stability	Advanced DRCC concept	Zr/La chemistry control
29	Medicine Hat Glauconitic C (MHGC)	Challenging; required pressure monitoring due to shallow depth	Maintained 44–60 cP; sensitive to high shear and bacterial activity	F&D cost ~$20/BOE; aimed to reduce operational life by 60+ years	Rapid breakthrough (48 hrs), “thief” zones, and recycling of polymer
30	Minagish Oolite	Excellent (≤6000 bpd)	Stable (up to 7.5 cP)	UTC ≈ $7–23/bbl	Tight fracture pressure window
31	Minagish Wara	Good	Stable (≈5 cP @ 1500 ppm)	Scalable PF candidate	Minor injectivity loss. Fracture-assisted flow interpretation
32	Murphy Seal	High initially			Performance drops significantly in zones where oil viscosity exceeds 14,000 cp
33	NIM-R Polymer Injectivity Trial	Matrix injectivity achievable at 150–250 m3/d; fracture initiation occurred at higher rates/viscosities	Polymer rheology from lab adequately explained in situ behavior; stable viscosities of 50–100 cP achieved during injection	Trial aimed to de-risk full-field polymer flooding and potential polymer savings via low-salinity hybrid (no economics quantified)	Unexpectedly low fracture pressure (≈7100–8300 kPa) led to fracture initiation/re-opening; changing well conformance and fracture propagation dominated injectivity response
34	Nimr-E Multiwell Trial	Pilot injectivity problems were mitigated	GRE-lined tubing used to limit degradation	Polymer selected over thermal alternatives based on economics, energy efficiency, CO2 intensity and complexity	Water coning, polymer loss to aquifer, produced polymer impact on reed beds, zonal-conformance control
35	Dalia & Camelia (Angola)		Polymer maintained viscosity at high salinity	5+ million bbl polymer injected by 2011; first-of-its-kind offshore EOR	Logistics challenges: deep-offshore, FPSO integration, large well spacing, high salinity
36	Offshore Abu Dhabi Carbonate	Injectivity limited; polymer injectivity not demonstrated at ~5 mD (injectivity index dropped from 0.44 to 0.06 m3/d/bar)	Polymers designed for HT/HS stability; mechanical degradation applied; stability proven at lab scale but field injectivity constrained	Objective was technical proof-of-concept rather than economics	Polymer injectivity insufficient in very low-k zone (~5 mD); injectivity lower than design expectation; need for multi-well pilot
37	Palogrande-Cebu	Slight reduction; injectivity broadly similar to waterflood, manageable with WHP ≤ 2400 psi	Moderate degradation observed in backflow test (~40% viscosity loss); affected by oxygen/iron control	Pilot technically successful	Administrative interruptions, polymer degradation risk (oxygen/iron), injectivity redistribution, well reactivations required
38	Patos-Marinza & Driza (Albania)	Good injectivity in heavy oil, but reduction in injectivity	—	—	—
39	Pelican Lake	Excellent injectivity in horizontal well patterns	Very stable at low T and modest salinity	Economically one of the largest PF projects	Sand issues; VRR complexities
40	RAUB UB2 LTPIT	Improved after design change	Stable post-optimization	Demonstrated scale-up viability	Early MW selection issue
41	Raudhatain Upper	Moderate → improved	Polymer MW too high → injectivity decline. Stable after polymer switch	Viable after optimization	Early injectivity failure with high-MW polymer
42	Rayoso-Grimbek	Good injectivity; retention acceptable	Stable; negligible degradation reported	Modular pilots reduced CAPEX, Strong incremental response	Water cut remains high; adsorption higher at salinity
43	Sabriyah Upper B.	Excellent (≤2000 bpd)	Stable (4.6–4.8 cP at 1600 ppm)	Commercially viable rates achieved	Permeability reduction (RRF ≈ 2.4)
44	Sabryah Mauddud	Excellent (matrix flow)	Stable at 1200–1600 ppm (3–5 cP in situ)	Positive UTC; feeder for commercial design	Near-wellbore skin required acid stimulation
45	Shuanghe Elevated-Temperature Pilot	High-MW polymer successfully injected	Thermal-degradation prevention specifically required	Reported utility 0.7 bbl incremental oil/lb polymer	Thermal stability, heterogeneity and need for profile modification
46	Sirikit Oil Field	Initially no injectivity issue; deterioration observed in several injectors over time, mitigated operationally	Polymer viscosity partly degraded during injection (designed ~7 cP; interpreted in situ ~3 cP from fall-off test)	Estimated positive net cash flow to date; final economic evaluation pending due to ongoing pilot and operational constraints	Injectivity deterioration; need for mechanical degradation (ROs); tubing leakage and ESP blockages; voidage replacement control challenges
47	South Turgay Pilot	Adequate injectivity. Injectivity stable; bottomhole pressure and injection rates varied insignificantly	Stable at reservoir conditions	Positive economics indicated by reduced water production and stabilized oil rate	Presence of fractures and high-permeability channels; need for viscosity ramp-up to control channeling
48	SZ36-1 Pilot	Significant response after eight months; injectivity/formation damage requires surveillance	Associative chemistry selected because conventional HPAM weakened in saline/hard brine	Demonstrated offshore feasibility where fresh water and platform space were limited	Limited platform footprint; no freshwater source; high hardness; laboratory evidence of adsorption/retention and possible core damage
49	Tambaredjo-Sarah Maria	Polymer injectivity poor without fractures; hydraulic fractures (~20 ft) increased injectivity dramatically. Observed polymer injectivity 0.40–0.63 (B/D)/psi.	Excellent. Improved anaerobic sampling showed polymer propagated >300 ft with essentially no loss of viscosifying ability. Produced polymer retained 31–34 cP at 896 ppm and 1600 ppm TDS.	Not reported. Paper discusses improved sweep and positive oil-response but provides no economic metrics.	Initial injectivity insufficient; injection above formation-parting pressure required. Short hydraulic fractures were created. Channeling stronger in some patterns (e.g., 1N062-1N11 trend). Produced polymer measurements were highly sensitive to oxygen contamination during sampling.
50	Umm Niqqa Lower Fars-High-Salinity 1-Spot Pilot	Excellent; polymer injected at ~100–120 bbl/d with sub-ambient wellhead pressure	Stable during pilot; polymer maintained ~30 cP (±20%) at 10 s−1 with oxygen control and additives	Use of produced water eliminates need for desalinated or low-salinity water; expected cost and logistics benefits	H2S presence required oxygen removal and scavengers; strict filtration and QC required; short test period and wellbore volume effects
51	Uzen	Good after MW optimization; commissioning ramp-up defined	Stable to reservoir temperature and salinity	Payback Year 3; polymer utility factor 50.6 t oil/t polymer	Water quality constraints (dissolved O2 <200 ppb, solids, iron); produced water unsuitable
52	XJ6	Injectivity maintained with moderate pressure increase (~2 MPa); water injection and liquid production increased ~20%	Stable during pilot; effective mobility control despite low temperature and heterogeneity	Economic data not reported; pilot demonstrated strong production response and sweep improvement.	Well and pump failures caused shutdown of 4 producers during injection phase; extreme heterogeneity and strong channeling required complex slug design
53	Yariguí–Cantagallo TAP	No injectivity loss; injection rate maintained (~600 bbl/d); fracture pressure not exceeded (≈3300 psi)	Stable after activation; viscosity increases after thermal activation and stabilizes after ~4 days	Reduced water handling cost; 6% improvement in energy intensity; carbon intensity reduced from 35.0 to 33.5 kg CO2/BO	Need for strict water-rate control; one event of overdosing due to flow fluctuations; requires careful QA/QC and single-well injection control
54	Zuata-Petrocedeño Pilot	Sustained; mobility decreased from ~342 to ~145 mD/cP over time	Good stability before injection; viscosity reduced by mixing with reservoir brine	Feasibility-oriented pilot; economics not quantified	Mobility reduction over time due to polymer retention, salinity mixing, possible shear degradation