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Senergy Formation Damage Presentation
- 1. Unlocking Hidden ReservoirPotential Through Integrated Formation Damage Evaluation (SPE 115690 and SPE 120694) Colin McPhee and Michael Byrne
- 2. Formation damage ├ Whatis 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. When is formationdamage 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. 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. Welltest in Well2 ├ 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. Core data ├ Extensivecore 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. Permeability model –Well 2 ├ MLR - best match to core
- 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. 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. 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. 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. 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. 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. Appraisal well 42/13-3design ├ 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. Geomechanics – strengthmodel 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. Geomechanics – stressmodel ├ 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. 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. Return permeability testson 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. Return permeability testresults 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. 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. 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. 42/13-3 well testresults ├ 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. 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. Formation damage incarbonates ├ 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. Conclusions ├ There aremany 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. Observations ├ Disciplinary compartmentalisationand 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. Thank you forlistening ├ Any questions…?