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Oilfield Scale: A New Integrated Approach to Tackle an Old Foe Dr Eric J. Mackay Flow Assurance and Scale Team (FAST) Institute of Petroleum Engineering Heriot-Watt University Edinburgh, Scotland Eric.Mackay@pet.hw.ac.uk Society of Petroleum Engineers Distinguished Lecturer 2007-08 Lecture Season
Outline 1) The Old Foe a) Definition of scale b) Problems caused c) Common oilfield scales d) Mechanisms of scale formation 2) The New Approach a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes 3) Conclusions Formation Water (Ba) Ba 2+ + SO 4 2- Injection Water (SO 4 ) BaSO 4(s) Slide 3 of 40
Outline 1) The Old Foe a) Definition of scale b) Problems caused c) Common oilfield scales d) Mechanisms of scale formation 2) The New Approach a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes 3) Conclusions Formation Water (Ba) Ba 2+ + SO 4 2- Injection Water (SO 4 ) BaSO 4(s) Slide 4 of 40
1a) Definition of Scale Scale is any crystalline deposit (salt) resulting from the precipitation of mineral compounds present in water Oilfield scales typically consist of one or more types of inorganic deposit along with other debris (organic precipitates, sand, corrosion products, etc.) Slide 5 of 40
Scale deposits 1b) Problems Caused formation damage (near wellbore) blockages in perforations or gravel pack restrict/block flow lines safety valve & choke failure pump wear corrosion underneath deposits some scales are radioactive (NORM) Suspended particles plug formation & filtration equipment reduce oil/water separator efficiency Slide 6 of 40
Examples - Formation Damage scale crystals block pore throats quartz grains Slide 7 of 40
Examples - Flow Restrictions Slide 8 of 40
Examples - Facilities separator scaled up and after cleaning Slide 9 of 40
Sand Grains Some Other Scales 1c) Common Oilfield Scales Name Formula Specific Solubility Gravity cold water other (mg/l) Common Scales SPE 87459 barium sulphate BaSO 4 4.50 2.2 60 mg/l in 3% HCl calcium carbonate CaCO 3 2.71 14 acid soluble strontium sulphate SrSO 4 3.96 113 slightly acid soluble calcium sulphate CaSO 4 2.96 2,090 acid soluble calcium sulphate CaSO 4.2H 2 O 2.32 2,410 acid soluble sodium chloride NaCl 2.16 357,000 (insoluble in HCl) silicon dioxide SiO 2 2.65 insoluble HF soluble Iron Scales: Fe 2 O 3, FeS, FeCO 3 Exotic Scales: ZnS, PbS Slide 10 of 40
1d) Mechanisms of Scale Formation Carbonate scales precipitate due to ΔP (and/or ΔT) wellbore & production facilities Ca 2+ (aq) + 2HCO- 3(aq) = CaCO 3(s) + CO 2(aq) + H 2 O (l) Sulphate scales form due to mixing of incompatible brines injected (SO 4 ) & formation (Ba, Sr and/or Ca) near wellbore area, wellbore & production facilities Ba 2+ (aq) (Sr2+ or Ca 2+ ) + SO 4 2- (aq) = BaSO 4(s) (SrSO 4 or CaSO 4 ) Concentration of salts due to dehydration wellbore & production facilities Slide 11 of 40
Outline 1) The Old Foe a) Definition of scale b) Problems caused c) Common oilfield scales d) Mechanisms of scale formation 2) The New Approach a) The new challenges b) Proactive rather than reactive scale management c) Effect of reservoir processes 3) Conclusions Formation Water (Ba) Ba 2+ + SO 4 2- Injection Water (SO 4 ) BaSO 4(s) Slide 12 of 40
2a) The New Challenges Deepwater and other harsh environments Low temperature and high pressure Long residence times Access to well difficult Compatibility with other production chemicals Inhibitor placement Complex wells (eg deviated, multiple pay zones) Well value & scale management costs Slide 13 of 40
Access to Well Subsea wells difficult to monitor brine chemistry deferred oil during squeezes well interventions expensive (rig hire) squeeze campaigns and/or pre-emptive squeezes Slide 14 of 40
Inhibitor Placement in Complex Wells Where is scaling brine being produced? P tubing head Can we get inhibitor where needed? wellbore friction pressure zones (layers / fault blocks) damaged zones P comp 1 P resv 1 Shale Fault Options: Bullhead bullhead + divertor Coiled Tubing from rig Inhibitor in proppant / gravel pack / rat hole P resv N P comp N Slide 15 of 40
Well Value & Scale Management Costs Deepwater wells costing US$10-100 million (eg GOM) Interval Control Valves (ICVs) costing US$0.5 1 million each to install good for inhibitor placement control susceptible to scale damage Rig hire for treatments US$100-400 thousand / day necessary if using CT deepwater may require 1-2 weeks / treatment cf. other typical treatment costs of US$50-150 thousand / treatment Sulphate Reduction Plant (SRP), installation and operation may cost US$20-100 million Slide 16 of 40
11 10 9 8 7 6 5 4 3 2 1 0 Number of SRP per Year and Total Capacity No of SRP plants Cumulative Capacity (BWPD) 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 1988 1989 1990 Year 5,000,000 4,000,000 3,000,000 2,000,000 1,000,000 0 Slide 17 of 40 No of SRP plants per year Cumulative Capacity (BWPD)
2b) Proactive Rather Than Reactive Scale Management Scale management considered during CAPEX Absolute must: good quality brine samples and analysis Predict water production history and profiles well by well brine chemistry evolution during well life cycle impact of reservoir interactions on brine chemistry ability to perform bullhead squeezes: flow lines from surface facilities correct placement Monitor and review strategy during OPEX Slide 18 of 40
2c) Effect of Reservoir Processes EXAMPLE 1 Management of waterflood leading to extended brine mixing at producers (increased scale risk) EXAMPLE 2 In situ mixing and BaSO4 precipitation leading to barium stripping (reduced scale risk) EXAMPLE 3 Ion exchange and CaSO4 precipitation leading to sulphate stripping (reduced scale risk) Slide 19 of 40
EXAMPLE 1 SPE 80252 Extended Brine Mixing at Producers Slide 20 of 40
EXAMPLE 1 SPE 80252 Extended Brine Mixing at Producers Field M (streamline model) This well has been treated > 220 times! Slide 21 of 40
EXAMPLE 2 Barium Stripping (Field A) SPE 60193 Barium (mg/l) Dilution line % injection water Slide 22 of 40
EXAMPLE 2 Barium Stripping (Theory) SPE 94052 Injection water (containing SO4) mixes with formation water (containing Ba) leading to BaSO4 precipitation in the reservoir Minimal impact on permeability in the reservoir Reduces BaSO4 scaling tendency at production wells Slide 23 of 40
EXAMPLE 2 Barium Stripping (Theory) Ba 2+ SO 4 2- (hot) Rock FW 1) Formation water (FW): [Ba 2+ ] but negligible [SO 4 2- ] Slide 24 of 40
EXAMPLE 2 Barium Stripping (Theory) Ba 2+ SO 4 2- (cold) (hot) Rock IW FW 2) Waterflood: SO 4 2- rich injection water displaces Ba 2+ rich FW Slide 25 of 40
EXAMPLE 2 Barium Stripping (Theory) (cold) Ba 2+ SO 4 2- (hot) BaSO 4 Rock IW FW 3) Reaction: In mixing zone Ba 2+ + SO 4 2- BaSO 4 Slide 26 of 40
EXAMPLE 2 Barium Stripping (Theory) [Ba] (mg/l) 900 800 700 600 500 400 300 200 100 0 0 20 40 60 80 100 seawater fraction (%) 3000 2500 2000 1500 1000 500 0 [SO4] (mg/l) Ba Ba (mixing) SO4 SO4 (mixing) Large reduction in [Ba] Small reduction in [SO 4 ] (SO 4 in excess) Typical behaviour observed in many fields Slide 27 of 40
EXAMPLE 2 Barium Stripping (Model & Field Data) barium concentration (ppm) 90 80 70 60 50 40 30 20 10 0 0 20 40 60 80 100 % seawater Field A - actual Field A - dilution line Field A - modelled Slide 28 of 40
EXAMPLE 3 Sulphate Stripping (Theory) SPE 100516 Injection water (with high Mg/Ca ratio) mixes with formation water (with low Mg/Ca ratio) leading to Mg and Ca exchange with rock to re-equilibrate Increase in Ca in Injection water leads to CaSO4 precipitation in hotter zones in reservoir Minimal impact on permeability in the reservoir Reduces BaSO4 scaling tendency at production wells Slide 29 of 40
EXAMPLE 3 Rock: 0.038 Ion Exchange Ĉ Mg = 0.50 C Mg FW: 0.077 Ĉ Ca C Ca IW: 3.2 C Ca Ca in solution 30,185 Mg in solution 2,325 C Mg Ĉ Ca Ĉ Mg Ca on rock Mg on rock Gyda FW (mg/l) IW (mg/l) 426 1,368 Slide 30 of 40
EXAMPLE 3 Sulphate Stripping (Theory) Ba 2+ SO 4 2- Ca 2+ Mg 2+ (hot) Rock FW 1) Formation water: [Ca 2+ ] and [Mg 2+ ] in equilibrium with rock Slide 31 of 40
EXAMPLE 3 Sulphate Stripping (Theory) Ba 2+ SO 4 2- Ca 2+ Mg 2+ (cold) (hot) Rock IW FW 2) Waterflood: [Ca 2+ ] and [Mg 2+ ] no longer in equilibrium Slide 32 of 40
EXAMPLE 3 Sulphate Stripping (Theory) Ba 2+ SO 4 2- Ca 2+ Mg 2+ (cold) (hot) Rock IW FW 3) Reaction 1: Ca 2+ and Mg 2+ ion exchange with rock Slide 33 of 40
EXAMPLE 3 Sulphate Stripping (Theory) Ba 2+ SO 4 2- Ca 2+ Mg 2+ CaSO 4 (cold) (hot) Rock IW FW 4) Reaction 2: In hotter zones Ca 2+ + SO 4 2- CaSO 4 Slide 34 of 40
EXAMPLE 3 Modelling Prediction: [Ca] and [Mg] 35,000 30,000 25,000 3,500 3,000 2,500 Ca Ca (mixing) Mg Mg (mixing) [Ca] (mg/l) 20,000 15,000 2,000 1,500 [Mg] (mg/l) 10,000 5,000 0 1,000 500 0 0 20 40 60 80 100 seawater fraction (%) Large reduction in [Mg] No apparent change in [Ca] Slide 35 of 40
EXAMPLE 3 Observed Field Data: [Ca] and [Mg] 40000 35000 30000 8000 7000 6000 Ca Ca (mixing) Mgl Mg (mixing) [Ca] (mg/l) 25000 20000 15000 5000 4000 3000 [Mg] (mg/l) 10000 2000 5000 1000 0 0 0 20 40 60 80 100 Large reduction in [Mg] No apparent change in [Ca] seawater fraction (%) Slide 36 of 40
EXAMPLE 3 Modelling Prediction: [Ba] and [SO4] 900 800 700 600 3000 2500 2000 Ba Ba (mixing) SO4 SO4 (mixing) [Ba] (mg/l) 500 400 300 200 100 0 1500 1000 500 0 0 20 40 60 80 100 [SO4] (mg/l) Small reduction in [Ba] Large reduction in [SO 4 ] (No SO 4 at < 40% SW) seawater fraction (%) Slide 37 of 40
EXAMPLE 3 Observed Field Data: [Ba] and [SO4] 300 250 3000 2500 Ba Ba (mixing) SO4l SO4 (mixing) [Ba] (mg/l) 200 150 100 50 0 0 20 40 60 80 100 seawater fraction (%) 2000 1500 1000 500 0 [SO4] (mg/l) Small reduction in [Ba] Large reduction in [SO 4 ] (No SO 4 at < 40% SW) Slide 38 of 40
3) Conclusions Modelling tools may assist with understanding of where scale is forming and what is best scale management option identify location and impact of scaling evaluate feasibility of chemical options thus providing input for economic model. Particularly important in deepwater & harsh environments, where intervention may be difficult & expensive But must be aware of uncertainties.. reservoir description numerical errors changes to production schedule, etc. so monitoring essential. Slide 39 of 40
Acknowledgements Sponsors of Flow Assurance and Scale Team (FAST) at Heriot-Watt University: Slide 40 of 40
Extra Slides Barium stripping example (Field G) Placement example (Field X) Slide 41 of 40
EXAMPLE G Barium Stripping (Field G) SPE 80252 a) water saturation b) mixing zone Field G (model) c) BaSO4 deposition (lb/ft 3 ) Slide 42 of 40
EXAMPLE G Barium Stripping (Field G) barium concentration (ppm) 250 200 150 100 50 Ba Ba (no precip) SO4 SO4 (no precip) [Ba] at well when reactions in reservoir [Ba] at well when no reactions in reservoir 3000 2500 2000 1500 1000 500 sulphate concentration (ppm) 0 0 0 500 1000 1500 2000 2500 Field G (model) time (days) Slide 43 of 40
EXAMPLE G Barium Stripping (Field G) barium concentration (ppm 250 200 150 100 50 Field B - observed Filed B - dilution line Field B - modelled deep reservoir mixing deep reservoir + well/near well mixing 0 0 20 40 60 80 100 Field G (model & field data) % seawater Slide 44 of 40
EXAMPLE X Impact of Reservoir Pressures on Placement Question for new subsea field under development: Can adequate placement be achieved without using expensive rig operations? Slide 45 of 40
EXAMPLE X Placement (Field D) SPE 87459 production 500 400 flow rate (m3/d) injection (squeeze) 300 200 100 0-100 -200 0 200 400 600 800 well length (m) prior to squeeze shut-in INJ 1 bbl/m INJ 5 bbl/m INJ 10 bbl/m 1 year after squeeze Good placement along length of well during treatment (> 5 bbls/min) Can squeeze this well Slide 46 of 40
EXAMPLE X Placement (Field D) SPE 87459 production 100 flow rate (m3/d) 0-100 -200-300 -400 0 200 400 600 800 prior to squeeze shut-in INJ 1 bbl/m INJ 5 bbl/m INJ 10 bbl/m 1 year after squeeze injection (squeeze) -500-600 well length (m) Cannot place into toe of well by bullhead treatment, even at 10 bbl/min Must use coiled tubing (from rig - cost), or sulphate removal Slide 47 of 40