Down Hole Flow Assurance

Transcription

1 Down Hole Flow Assurance Ferhat Erdal Senior Advisor - Flow Assurance Steve Cochran Senior Advisor - Flow Assurance SPE GCS Annual Drilling Symposium Spring, TX April 13, 2017

2 Flow Assurance Key Words SCSSV Setting Depth SITP Scale Hydrate Wax Corrosion Asphaltene Chemical Injection Methanol Glycol LDHI Corrosion Inhibitor Scale Inhibitor Gas Lift ESP Scale Squeeze Acid Job Sand Slugging Erosion JT Cooling/Heating Water Hammer VIT Insulation Proppant Annulus Management SCSSV Testing Cooldown time Warmup time Maximum Temperature Minimum Temperature OHTC Fluid & Material Compatibility C-Factor Multiphase Flow Correlations OLGA Fluid properties Geothermal Temperature Gradient Emulsion Souring Etc. 2 2

3 Hydrates Hydrate Formation Locations Tubing Annulus Safety Valves Well Servicing Well Control Equipment Wireline Lubricators Wellheads and Trees Chokes Chemical Injection Lines Outside of well Petrobras 3

4 Hydrate Risk Zone MeOH SI DE MeOH Gas Hydrate Risk Zone and SCSSV Setting Depth Compare hydrate curve, SITP conditions and geothermal temperature gradient. Determine hydrate formation temperature, pressure, and depth. From geothermal temperature gradient, determine boundary depth for hydrate risk zone. Consider effect of Gas lift ESP MV WV CV SDV SCSSV GLM ESP PT /TT 4

5 TVD (feet) Pressure (psia) T vs P Steady-State Cases N2 (k= W/m-K) in annulus 'A' - Insulgel (oil based) in annulus 'B' Bottom hole 8000 Hydrate Management Shutdown Cooldown time Re-Start Warmup time Inhibitor Injection: rate, duration, volume Insulation Bullheading Depressurization Coiled Tubing Hydrates Temperature (F) No hydrates 5 mbd mbd Well head Flow 15 mbd 20 mbd 25 mbd 30 mbd SS 5 mbd SS mbd SS 15 mbd SS 20 mbd SS 25 mbd SS 30 mbd Hydrate formation water Hydrate Seawater 0 Temperature (F) A5 SS Mud Line Hour Shut-In 5 Hour Shut-In 24 Hour Shut-In Extended Shut-In 7000 Hydrates No Hydrates 5

6 Scale Precipitation and deposition of inorganic minerals within the production wells and processing equipment. Depends on several of factors Water Composition ph Pressure Temperature CO 2 Concentration Compatibility of Waters Chemicals Affecting Solubility Limits Nalco 6

7 Pressure, psia Calcite Scaling Calcite scaling tendency increases with increasing temperature and decreasing pressure. High up in the tubing due to lower pressures Around ESP due to high temperature At downhole flow restrictions (Perforations, nipples, etc.) Precipitation can occur as the ph of the brine increases. Unlike many salts, the solubility of CaCO 3 decreases at higher temperature Resulting in precipitation in heat transfer equipment or ESP s 18,000 Calcite Scaling P/T Profile at Scaling Threshold (SI=0.4) Mixing incompatible waters can also increase carbonate scaling tendency. Carbonate Scales can develop low in the well, clogging downhole equipment, and plugging perforations. 16,000 14,000 12,000,000 8,000 6,000 4,000 2,000 SI<0.4, non scaling Reservoir / Sea Water Fraction 0/0, SI=0.4 80/20,SI=0.4 50/50,SI=0.4 20/80,SI=0.4 0/0,SI=0.4 Pi=2, 0%WC Pi=2, 40%WC Pi=2, 80%WC 20/80 0/0 50/50 80/20 0/0 Reservoir SI>0.4, Scaling WH BH ESP Temperature, o F 7

8 Pressure, psia Barium Sulfate Scaling Barite scaling tendency increases with decreasing temperature or decreasing pressure with temperature having a greater effect. It is generally a problem in the upper well bore or production facilities. Mixing sulfate-rich seawater with barium-rich formation water most common risk. Seawater injection can lead to sulfate scaling in the reservoir due to water incompatibility When seawater is used in a workover or completion operation, sulfate scales are also a risk then When water flooding with seawater, there typically is a risk of Sulfate Scales It is common to remove sulfate from seawater if it will be used for water flooding 40,000 35,000 30,000 25,000 20,000 15,000,000 Barite Scaling P/T Profile at Scaling Threshold (SI=0.8) Reservoir/ Sea Water Fraction 0/0, SI = /20, SI = /50, SI = /80, SI = 0.8 Pi=2, 0%WC Pi=2, 40%WC Pi=2, 80%WC 0/0 80/20 50/50 20/8 SI<0.8, non scaling Reservoir 5,000 SI>0.8, Scaling BH ESP WH Temperature, o F 8

9 Scale Mitigation and Remediation Preemptive Scale Squeeze Down Hole Scale Inhibitor Injection Scale Squeeze Acid Injection Coiled Tubing 9

10 Wax Risk Zone MeOH SI DE MeOH Gas Wax Deposition Wax deposits in the upper portion of the wellbore, where the fluids have cooled below the cloud point or WAT. WAT varies greatly in oils and condensates; it can range between F Pour point also varies depending of wax content. It can range F. Wax deposition is temperature driven. Temperature Control Preventing hydrocarbons from cooling prevents wax from depositing MV WV CV SDV Vacuum insulated tubing Insulating packer fluid Low risk during shutdowns High risk operating at low rates and temperatures SCSSV GLM ESP PT /TT

11 Wax Management Wax Inhibitors and pour point depressants (PPD) injection Hot Oiling Hot Oil is circulated in the well, melting any wax in the well, allowing it to be flowed out Chemical Solvents Terpenes or Aromatic Solvents can be effective at wax removal Mechanical Removal Slick line operation to cut was deposition from the inside of the tubing combined with solvent soaking. Frequency of wire line interventions Well downtime during wax cutting Risk of sticking wire line tools Coiled Tubing (to inject hot fluid or solvent) 11

12 Transmitted Light (Watt) P (psia) psi psi psi psi 1 psi 0 psi 9000 psi 8000 psi 7500 psi 7000 psi 6500 psi Asphaltenes psia 5000 psia 8000 psia psia psia Asphaltenes may precipitate when the fluid conditions change (particularly pressure) or incompatible fluid streams are mixed. Transition across the bubble point results in a major change in density and thus a change in asphaltene stability Further changes in pressure will result in changes in density Mixing of heavy oil with lighter oil Gas Lift CO 2 Injection Bubble point pressure: 1860 psia at 182 o F 1200 psia T=204 F Bubble point Upper boundary Lower boundary Pressure, psia Onset pressure: 6000 psia at 182 o F?? Precipitation Total GOR (scf/stb) 12

13 Asphaltene Management Asphaltene inhibitors can be injected downhole. Asphaltene inhibitors do not inhibit Asphaltene precipitation, but they disperse precipitated Asphaltenes. Pressure Control Pressure decreases can cause Asphaltenes to precipitate, providing pressure support can prevent this. Aromatic solvents (xylene soaking) Frequency Duration 13

14 Erosion and Sand Sand production rate is generally an input from completions and some times it is go-by number. Sand production and erosional limits can be determined by using API 14 E TULSA Model CFD Selecting right location for sand monitoring is key. In the operations phase online monitoring is used to detect sand influx. Production rate control is used to stay within allowable limits Sand prone wells can be re-completed Water hammer could cause fines migrations Bullheading through gravel pack (used to displace water below SCSSV for hydrate control) may affect completion, leading to sand production 14

15 TVD (m) Transient Multiphase Flow Modeling 0 Distance (m) Slugging Slug flow is the dominant flow regime in upward flow. Complex well geometries, especially long horizontal wells. Toe up Toe down Low flowrates Changes in flow conditions Complex Thermal Modeling Counter current flow Intervention Modeling Drilling Well kill Near wellbore flow modeling 15

16 Artificial Lift and Flow Assurance Pumps cause major changes in downhole systems Significant Pressure increase Asphaltene Deposition Scale Precipitation Added Heat to the system ESP s generate significant heat, this can cause scale to precipitate, especially at the outer surface of the pump. High viscosities due to tight emulsions also adversely affect pump efficiency Erosion 16

17 Artificial Lift and Flow Assurance Gas lift can also change FA issues down hole Gas lift expands hydrate formation conditions and increases risk for hydrate formation. Gas lift can cause Asphaltene precipitation. Gas lift injection through annulus can cause lower temperatures in the upper part of the tubing which can cause wax deposition. 17

18 MeOH SI DE MeOH Gas Chemical Injection Locations Wellhead Injection To support well and downstream operations Methanol / Glycol LDHI Scale Corrosion MV WV CV SDV. SCSSV Injection Generally for Hydrate Management Methanol / Glycol LDHI SCSSV GLM ESP Deep Downhole Injection Continuous Production treatment Scale Wax Asphaltene Emulsion Corrosion H 2 S Scavenger PT /TT Chemical Squeezes Scale Asphaltene 18

19 MeOH SI DE MeOH Gas Chemical Injection Design Flow Assurance determine chemical injection MV WV CV SDV Location Control line size Rate SCSSV Pressure GLM Time and duration (continuous vs. intermittent) ESP Operability (cracking pressure) PT /TT 19

20 Flow Assurance Famous Scary Pictures Petrobras Hydrate Asphaltene Stat Oil Wax Nalco Scale WAX Slugging Stat Oil 20 20

21 Flow Assurance Integration Flow Assurance helps identify Risk Mitigation/Management Contingency Develop Procedures Flow Assurance works with interfaces Reservoir Production Engineers Artificial Lift D&C Surface and Subsea Facilities 21

22 Questions? 22