Senergy Formation Damage Presentation

4,872 views

Published on

Presentation on formation damage by Colin McPhee from Senergy, given to SPWLA Abu Dhabi Chapter on 5th Nov 2009

2 Comments
3 Likes
Statistics
Notes
  • thanks
       Reply 
    Are you sure you want to  Yes  No
    Your message goes here
  • Acronyms are a pain...OBM is possibly Oil Based Mud ...and if that is the case then perhaps WBM is Water Based Mud ...I've been in this business 32 years and I've never heard of some of the other acronyms...

    Wouldn't be so bad if you spelled them out with the first usage, Oil Based Mud (OBM) etc would be extremely helpful
       Reply 
    Are you sure you want to  Yes  No
    Your message goes here
No Downloads
Views
Total views
4,872
On SlideShare
0
From Embeds
0
Number of Embeds
17
Actions
Shares
0
Downloads
238
Comments
2
Likes
3
Embeds 0
No embeds

No notes for slide

Senergy Formation Damage Presentation

  1. 1. Unlocking Hidden Reservoir Potential Through Integrated Formation Damage Evaluation (SPE 115690 and SPE 120694) Colin McPhee and Michael Byrne
  2. 2. Formation damage ├ What is formation damage? ├ any reduction in near wellbore permeability which is the result of “any stuff we do” ├ ……….such as drilling, completion, production, injection, attempted stimulation or any other well intervention ├ What is the impact? ├ Shell has estimated that (at an oil price of less than $20/bbl) the cost of damage on Shell-operated assets was $1 billion/year. ├ Shell, at that time, was producing roughly 3.3 % of total world production. ├ Today, $70/bbl and global perspective means current best estimate for cost of damage due to deferred production and dealing with damage is: $100 billion/year
  3. 3. When is formation damage important? ├ Prospect /development planning ├ correct selection of field development options ├ consideration of formation damage should be an integral part of production or injection optimisation process ├ Development wells ├ best to minimise damage ├ but can also remove damage ├ Exploration and appraisal wells ├ identify potential in undeveloped discoveries. ├ recognising and diagnosing formation damage can unlock hidden reservoir potential ├ Two field examples ├ others undoubtedly exist elsewhere
  4. 4. Example 1 - oil field ├ Two appraisal wells drilled in 10000 early 90’s ├ Well 1 drilled with OBM and 1000 cored. High water saturations near OWC ├ Well 2 drilled with WBM and 100 cored. DST tested. ├ Rock properties (core) Air Permeability (mD) ├ ka from 0.1 mD to 500 mD 10 (mean 10 mD) ├ clay minerals and carbonate cements 1 ├ kaolinite – up to 73% of clay fraction ├ pore lining chlorite (20% to 0.1 40%) and illite (10% to 18%) 0.01 0.00 0.05 0.10 0.15 0.20 0.25 0.30 Helium Porosity (fractional)
  5. 5. Welltest in Well 2 ├ DST 1/1a ├ perforated underbalanced (700 psi) ├ well flowed naturally for four hours then died. Under N2 (CT) rate stabilised around 350 stb/d. ├ Stimulated with mud acid ├ PLTs show post-acid flowrate is around 50% of the pre-acid rate ├ Initial operator’s WTA interpretation ├ kh ~ 2030 mDft ├ k = 6 mD ├ S = -1.3 ├ Operator relinquished licence ├ New operator saw productivity potential from core ├ welltest re-interpreted ├ pseudo-PLT constructed from core data and compared with well PLT
  6. 6. Core data ├ Extensive core dataset from Well 1 and 2 ├ RCA “fresh-state” oil permeability (ko) at stress ├ routine air permeability (ka) at 400 psi ├ SCAL ko at stress ├ Permeability model at reservoir conditions ├ ka enhanced by core drying (clay damage) ├ convert to reservoir conditions ├ absolute (ka) to effective (ko @ Swir) conversion ├ CBW correction ├ stress correction ├ core to log transform ├ predict reservoir condition permeability over entire reservoir interval
  7. 7. Permeability model – Well 2 ├ MLR - best match to core
  8. 8. Core permeability correction Fresh-state Ko data 1000 Fresh-state Oil Permeability at 3000 psi (mD) 100 1.2839 y = 0.1389x 2 R = 0.7944 10 1 0.1 0.01 0.001 0.01 0.1 1 10 100 1000 Air Permeability at 400 psi (mD)
  9. 9. Core permeability correction SCAL Data 1000 100 Ko at 4500 psi (mD) 10 SCAL data Equality 1 0.1 0.01 0.1 1 10 100 1000 Ka at 400 psi (mD)
  10. 10. Pseudo-PLT ├ Core ko to cumulative oil rate Cumulative Layer Contribution (fraction) 0.0 0.2 0.4 0.6 0.8 1.0 8350 Q Darcy’s Law h1K1 Q1 A ∆P 8400 Q = K. h2K2 Q2 L µ H Q3 8450 h3K3 Qi = K i .hi Const .∆ P h4K4 Q4 Q = Q1 + Q 2 + .... + Qi Qi Depth (ft MDRKB) hiKi 8500 H = h1 + h2 + ... hi KoMOD1 KoMOD2 ∆P ∑hK 8550 K arith = i i H (P − P ) 8600 0.00708kh( wt ) qo = i wf µ o Bo ⎡ ⎛ 0.472re ⎞ ⎤ ln⎜ ⎢ ⎜ ⎟ + S '⎥ 8650 ⎟ ⎣ ⎝ rw ⎠ ⎦ 8700 ├ PLT overlay suggests thin high quality intervals are damaged
  11. 11. Productivity and skin ├ Short build up (weather) ├ re < h ├ Radial flow not established ├ k is function of kh and kv ├ No definitive interpretation is possible ├ Little justification for the interpreted negative skin factors in original interpretation ├ Cryogenic SEM showed filtrate retention in core tests ├ Large pressure surge on perforating dislodged mobile fines (kaolinite and illite) from RETAINED MUD FILTRATE LOSSES the formation? BEFORE TEST AFTER TEST ├ Post mortem encouraging enough to plan new appraisal drilled with non-damaging DIF Fluid has been retained in the micropores between the chlorite platelets
  12. 12. Example 2 – Gas Well SOUTH NORTH ├ Appraisal well 42/13-2 (1998) Base Chalk ├ Late Cretaceous-Early Tertiary Inversion 66 ft pay in 400 ft gas column ├ average φ =13.4% ├ average Sw = 32% Top Triassic ├ core permeability from 0.5 mD to 478 mD (average ~ 10 mD) Top Zechstein Top Rotliegend Breagh Gas Accumulation ├ 3%-5% pore filling clays Top Carboniferous (kaolinite and illite) Cleveland Basin Dogger High ├ 36% to 45% of pore throats < 1 micron Breagh Structural Cross Section ├ Poor test results – original operator relinquished licence ├ New operator commissioned Pore filling Pore filling illite kaolinite integrated study to evaluate well results and drill and complete new appraisal well Quartz utilising best practice in well overgrowths construction
  13. 13. 42/13-2 formation damage ├ Reservoir exposed to heavy salt brine at around 400 psi overbalance then displaced with sea water ├ 5 intervals perforated at 1550 psi underbalance using TCP-conveyed 4 ½” RDX guns ├ Produced at only 3 mmscf/d ├ Test results: ├ main pressure build up was affected by changing well bore storage, masking the radial flow period ├ Best match the main pressure drawdown indicated kh = 158 mDft and damage skin (S) of +47 ├ WBM filtrate invasion between 30 – 60 inches from the wellbore (7450 ft to 7500 ft MD) ├ perfs may not have penetrated beyond invaded and damaged zone Logs show deep invasion between 7450 ft and 7500 ft mD
  14. 14. Appraisal well 42/13-3 design ├ Vertical cased and perforated well ├ Key issues in well design: ├ could the reservoir section be drilled at minimum overbalance without compromising drilling or completion operations? ├ could the well be tested or produced without sand failure or sand production (common problem in SNS)? ├ could the well DIF be designed to prevent or minimise formation damage during conventional drilling? ├ Underbalance drilling had cost issues ├ drill conventionally at minimum safe overbalance (+ 0.4 ppg) ├ Integrated geomechanics/formation damage study ├ evaluate wellbore stability with 10.1 ppg mud ├ assess risk of sand failure and sand production during testing ├ characterise formation properties and carry out return permeability tests using water-based and oil-based DIFs
  15. 15. Geomechanics – strength model TWC Strength Model Probability Distribution (based on 42/13-2 :7375 - 7885 ft MD) ├ Log-derived strength 100% 90% Pay Interval model Percentile TWC probability (Cumulative Frequency) 80% (psi) P5 12160 70% P10 12439 Net Interval UCS = 1798E c − 3574 P20 12912 Percentile TWC (psi) 60% P30 13086 P5 12350 P40 13306 P10 12802 Net 50% P50 13527 P20 13215 Pay P60 13761 P30 13592 1.34 x1010 ρ b 40% P70 13940 P40 13888 P80 14180 P50 14101 Ec = P90 14464 P60 14317 30% P70 14714 P95 14733 ∆t 2 P80 15132 20% P90 15617 P95 17059 10% 0% TWC 8000 10000 12000 14000 16000 18000 20000 = 12.24UCS −0.4696 TWC (psi) UCS ├ Calibrated by tests on Core Saturation Confining Failure Young's Poisson's Cohesive Friction Depth Fluid Pressure Stress Modulus Ratio Strength Angle (ft MD) (MPa) (psi) (Mpsi) (-) (psi) (deg) 42/13-2 core 7467.21 7467.21 Oil Oil UCS 18 5746 17319 2.82 0.249 1365 39.2 7478.21 Oil UCS 5464 7478.21 Oil 18 21544 3.94 0.196 1101 46.1
  16. 16. Geomechanics – stress model ├ Vertical stress ├ density log integration 42/13-2 ├ Horizontal stresses ├ LOT, image logs in 42/13-2 ├ pore pressure ├ RFT ├ Analogue database ├ stress tensors validated against offset data Total Maximum Minimum Pore Vertical Stress Horizontal Stress Horizontal Stress Pressure (psi/ft) (psi/ft) (psi/ft) (psi/ft) 1.00 0.80 0.72 0.501
  17. 17. Geomechanics - results ├ Wellbore stability ├ well could be drilled with minimum overbalance without risk of collapse ├ Sand production ├ no risk of sand failure at test conditions or if well Well could be drilled at 10.1 ppg with no problems produced over life of field ├ completion design 42/13 Generic Cased and Perforated Completion Vertical Well: BF = 3.1 Sv = 1.00 psi/ft; SH = 0.80 psi/ft, Sh = 0.72 psi/ft, pp = 0.501 psi/ft TWC = 12160 psi (P5 TWC) simplified and failure risks 6000 4000 minimised by avoiding sand 2000 0 0 deg control -2000 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 10 deg 20 deg 30 deg BHFP (psi) -4000 40 deg -6000 50 deg 60 deg -8000 70 deg 80 deg -10000 90 deg -12000 BHFP = Pres -14000 -16000 -18000 Pres (psi) No sand production for vertical C&P well
  18. 18. Return permeability tests on 42/13-2 core ├ WB and OB DIFs formulated on basis of: 1 ├ average formation permeability ~ 10 mD 0.9 ├ clay content (3% - 5%) and pore size 0.8 distribution (~40% < 0.5 micron) 0.7 ├ Return permeability tests at reservoir Mercury Saturation (PV) 0.6 conditions 0.5 ├ replicate field placement/overbalance 0.4 Microporosity (from 10.1 ppg mud) 0.3 ├ 48 hours dynamic imbibition and 48 hours 0.2 static imbibition 0.1 ├ Imbibition (fluid loss) 0 ├ Monitor DIF fluid loss (fraction of pore 0.001 0.01 0.1 1 10 100 Pore Throat Size Radius (microns) volume) ├ kg versus kg (reference) ├ after DIF exposure (worst case) ├ after mud cake removed (best case) ├ after remaining filtrate spun out (permanent damage)
  19. 19. Return permeability test results Low permeability interval High permeability interval 100% 100% 90% Return Permeability Ratio (% Reference Permeability) 90% Return Permeability Ratio (% Reference Permeability) OBM: 45% damage OBM: 27% damage OBM: 6% permanent damage OBM: 38% damage OBM: 26% damage OBM: 3% permanent damage WBM: 62% damage WBM: 30% damage WBM: 24% permanent WBM: 72% damage WBM: 58% damage WBM: 29% permanent 80% d 80% 70% 70% 60% 60% #3 OBM #9 OBM 50% 50% #4 WBM #10 WBM 40% 40% 30% 30% 20% 20% 10% 10% 0% Mudcake Removed 0% Mudcake Removed 1 Mudcake Removed 2 Filtrate Removed 3 Mudcake In Place 1 Mudcake Removed 2 Filtrate 3 Removed Mudcake In Place Plug Helium Air Reference Mud Total Return Return Return Code Porosity Permeability kg at Swi Type Filtrate Permeability Permeability Permeability No. Loss with mud w/out mud after spin cake cake* down** (fraction) (mD) (mD) (PV) (mD) (mD) (mD) 9 0.144 75.3 51.8 OBM 0.52 32.2 38.3 50.4 10 0.175 127 103 WBM 1.48 29.2 43.5 72.7 3 15.9 17.8 14.2 OBM 0.58 7.8 10.4 13.3 4 13.1 10.5 5.78 WBM 2.32 2.2 4.0 4.4 Notes: * Mud cake removed manually ** Core extracted in centrifuge to remove remaining filtrate
  20. 20. Damage mechanisms Filtrate Loss Comparison - Low Permeability 3.00 ├ Imbibition Dynamic Filtration Static Filtration 2.50 ├ OBM imbibition complete after ~ 25 2.00 Total Filtrate Loss (PV) hours Continual filtrate loss ├ WBM filtrate imbibition continues #3 OBM 1.50 Rapid spurt loss #4 WBM unabated due to strong capillary 1.00 forces Negligible filtrate loss ├ Permeability damage 0.50 ├ WBM-treated samples suffered a 0.00 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 Square Root of Time (hours) permanent permeability damage of Filtrate loss curves for WBM and OBM DIFs 24% and 29%, compared to only 3% to 6% for the OBM-treated Retained aqueous fluid cores layer draping grains and ├ Damage mechanisms restricting pores ├ retention of WBM filtrate in pore system reduces permeability to gas ├ filtrate invasion has dispersed, dislodged and suspended kaolinite and illite fines in the fluids ├ solids mud invasion at wellbore face ├ Supports 42/13-2 well results Cryogenic SEM shows WBM filtrate retention with filtrate draping grains and restricting pores
  21. 21. 42/13-3 well results ├ Drilling and completion ├ drilled with 10.1 ppg oil- based DIF with no wellbore instability issues ├ Cased and perforated ├ Reservoir ├ two good quality sands ├ 7358 ft MD to 7387 ft MD ├ 7413 ft MD to 7435 ft MD ├ 77 ft net pay in 296 ft gas column
  22. 22. 42/13-3 well test results ├ Productivity ├ perforated between 7340 ft 4000 13 2 Well Test IPR 13 3 Well Test IPR and 7450 ft MD on 3 ½” OD 3500 BHFP 42/13-3 BHFP 42/13-2 B o tto m H o le F lo w in g P re s s u re (p s ia ) TCP test string 3000 ├ test kh ~ 237 mDft 2500 ├ damage skin 0 to +2 2000 1500 ├ 17.6 mmscf/d compared to 3 1000 mmscf/d in 42/13-2 500 ├ AOF 10 times 42/13-2 AOF 0 0 5 10 15 20 25 30 ├ Success Gas Production rate (MMscf/d) ├ well proved connectivity of channels ├ Encouraged JV partners to plan field development
  23. 23. Latest……… ├ Horizontal well ├ cased and perforated completion ├ same OBM DIF as 42/13-3 ├ drilled at minimum overbalance ├ Tested January 2009 ├ tested dry gas at 26 mmscf/d ├ mechanical skin ~ 0 May 25 2009 ├ Estimated reserves 600 Bcf ├ Largest undeveloped gas field in SNS? ├ Anticipated sale price $1Billion
  24. 24. Formation damage in carbonates ├ Carbonates tend to have been neglected as they are more complex than clastics ├ Strong imbibition forces in tight matrix retain WBM filtrates and reduce hydrocarbon productivity ├ Whole mud losses plug fractures ├ Design the well with fractures in mind – these are often the reservoir and should be protected if possible from any damage or flow restriction ├ Drilling and completion fluids tend to be self-evaluated by the fluid vendors. Independent evaluation of potential damage and stimulation in heterogeneous carbonates is essential ├ Consider underbalance drilling and/or completion to minimise losses and fracture damage
  25. 25. Conclusions ├ There are many fields that have been condemned to be non-viable as a result of poor well productivity rather than poor permeability or connectivity. ├ An integrated petrophysical, geomechanical and formation evaluation solution can recognise, diagnose and help mitigate against formation damage. ├ Significant development opportunities can be realised in “uneconomic and non-viable” oil and gas fields
  26. 26. Observations ├ Disciplinary compartmentalisation and unaligned KPIs can combine to overlook or bypass viable opportunities, losing the value initially to the operator itself, and potentially to the rest of the industry. ├ The key to the revival of this “toxic asset” has been the willingness of this operator to: ├ take calculated risks in a risk-averse climate ├ foster and encourage an integrated, multi- disciplinary approach that draws on the combined skills of geologists, petrophysicists, drilling, reservoir and production engineers.
  27. 27. Thank you for listening ├ Any questions…?

×