Best Practice for Stand-alone Screens

Best Practice for Stand-alone Screens Ian Wattie Completion Engineering Consultant Yala Peak Limited Sand Management Forum 26 th 27 th March 2014 Aberdeen 1

Stand-alone Screens Best Practices Completion Failure % 90 80 70 60 50 40 30 20 10 0 Industry Completion Failure Data Data for OH Completions with Stand-Alone Screens Highest Failure Rate for Major Operator: 15 Failures/19 Wells Average Failure Rate from Industry Database: 39 Failures/110 Wells Lowest Failure Rate of Major Operators: 4 Failures/71 Wells Industry Worst Industry Average Industry Best 2

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2000 1800 1600 1400 1200 1000 800 600 400 BHP (psia) Oil rate (bbl/d) BSW (% x 10) 200 0 1-Nov-10 1-Dec-10 1-Jan-11 1-Feb-11 1-Mar-11 1-Apr-11 1-May-11 1-Jun-11 1-Jul-11 1-Aug-11 1-Sep-11 6

Field Case Causes of Production Decline/Disappointment 1. Sand control best practices for selection, design, manufacturing, installation & start-up mostly not followed 2. First wells had no sand control based on log-derived UCS 3. Short length screens and large annular gap have much bigger effect than other bad practices 4. Very short screens will plug or erode sooner due to higher rates/metre 5. Very short (e.g. < 10 metres) screen mesh intervals are extremely sensitive to anything less than ideal practice at every stage 6. Screen mesh size too small; very large D 10 sand size 7. Screens run in brine > 250 NTU picking up debris 8. Screens needed to be worked past shale picking up swelling shale 9. Lower post-acid loss rate 0.5 bpm - did not clean off all filter cake 10. Production declines are fines plugging formation or screen 11. Sudden changes in production are wellbore collapse onto screen, plugging the screen and reducing annulus permeability with resorted sand, shale and residual mud-cake 7

Sand Control Best Practices Outline Sand failure risk assessment Sand control strategy selection Sand screen selection method Sand screen manufacturing QA & QC Completion installation practices Production start-up 8

Sand Control Best Practice Sand failure risk assessment - risk of sand production Strength characterisation Stress characterisation Formation failure modelling 9

Comparison of Log Predicted UCS with Core Measured UCS Log Predicted UCS, psi 25000 20000 15000 10000 5000 Field-1 Samples Field-2 Samples Field-3 Samples Field-4 Samples Unit Slope Line 0 0 2500 5000 7500 10000 12500 15000 Core Measured UCS, psi 10

Core Samples Used in UCS Testing 11

Formation Strength Characterization Use of Core Data to Establish UCS Range 10000 Example Formation Strength Characterization Core Measured Unconfined Compressive Strength vs. Depth Unconfined Compressive Strength, psi 8000 6000 4000 2000 0 7300 7400 7500 7600 7700 7800 7900 Measured Depth, ft MDRKB 12

Formation Stress Characterization Principle Stresses = Vertical, Hz-max, Hz-min Absolute Stress = Total Stress Acting at Depth Net Stress = Absolute Stress - Pore Pressure Depletion Forecast, so Net Stress increases over field life 13

History Matching with Field Data 3500 Comparison of Field Sand Production Data with Model Prediction Conventional Wells with Standard, Non-Stress Oriented, Perforations Bottomhole Pressure, psi 3000 2500 2000 1500 1000 500 No Sand Production Failure Prediction Sand Production Unit Slope Line 0 0 500 1000 1500 2000 2500 3000 3500 Reservoir Pressure, psi 14

Sand Control Best Practice Select strategy for sand management Produce sand to facilities, collect and dispose Prevent formation failure (wellbore orientation, fracture and perforation tactics, resin stabilisation, increase pressure, choke back well, shut-in well, redrill well) Screen out at sand face (stand-alone screen, gravel pack, frac-pack) 15

Sand Control Best Practices Select and design stand-alone sand control screen Select most likely screen type mesh sizes around D 10 from PSD select maximum od screen size to minimise annulus (max 1 less than nominal hole size drilled) Sand screen mesh sizing by proven lab testing methods Plugging resistance test flow and return perms (screen & sand pack) Sand retention RDIF selection by testing Drillability (inc. shale stability, loss control, rheology) Completability (inc. formation damage, screen plugging) Clean-up treatment by testing Screen coupon from production line mesh Sand as per PSD RDIF with drill solids (including shale) Clean-up fluid at representative volume 16

Formation Sand Variation Sample Selection Particle Size Distribution of Formation Sand Samples 100 90 High Perm Sand Low Perm Sand Worse Case 80 Cumulative % (wt.) 70 60 50 40 30 20 10 0 1000 100 Grain Diameter (microns) 10 17

Test Procedures for Screen Qualification Gradual Formation Failure Flow at constant dp Produced solids conc. and particle size Initial / final sand pack, gravel and screen perms 18

Reservoir Drill-In Fluid Selection Performance Test Criteria Fluid Loss Control Bridging Agent PSD Bridging Agent Conc Polymer/Starch Conc Rheology Polymer Conc Reactivity Formation Damage Filtrate / Solids Invasion Filtercake Restriction Drill Solids Conc / Reactivity Screen Plugging Filtercake Plugging Shale stability 19

Clean-up System Testing Integrated test of: RDIF (with drill solids inc shales) Clean-up fluid volume, circulation, pressure and temperature, soak time Flowback onto screen Screen plugging measurements: flow initiation pressure retained flow capacity peak pressure 20

Screen Plugging Tests Formation Sand Filtercake 12.2 ppg OBM w/ 7.5% HCL +25% EGMBE 12.2 ppg OBM w/ Super Pickle + Mark II Formation Sand 12.2 ppg NaBr/KCL WB DIF #3 w/ EDTA 12.2 ppg NaCL/KCL/NaBr WB DIF w/ EDTA 21

Integrated System Testing Callanish DIF/Screen/Clean-up & Brodgar Screen Test Results Plugging Test Results 100 %Ret K Results graph of retained productivity % Retained % Flow Screen Capacity) K 10 1 0.1 0.01 Peak dp 100 80 60 40 20 Peak dp (psi) 0.001 12.2 ppg 12.2 ppg 12.2 ppg NaCL/ Fordacal/MilBar Fordacal/MilBar KCOOH Fordacal Enviromul OBM OBM # 2Enviromul OBMKCL/NaBr OBM WBM# 2OBM # 2328 OBM # 2328 WBM # 32326 WBM SuperPickle w/ SuperPickle + 7.5% + HCL + EDTA w/ 7.5% HCL SuperPickle + + 7.5% HCL w/ + EDTA EDTA HDC MarkII XYZ MarkII +25% EGMBE 25% EGMBE HDC MarkII 25% EGMBE Callanish(Halliburton) Brodgar(Baker) 0 22

Sand Control Best Practices Procurement Qualification testing (for specific screen design & manufacturing location supplying project) Corrosion testing weave (completion & production fluids) Bead testing mesh size Burst & collapse full size joint Assess assembly, inspection, repair and quality control procedures Manufacturing quality control Inspect records for satisfactory performance Inspect screens for correct assembly and signs of repair 23

Sand Control Best Practices Field installation Drill reservoir with RDIF MBT < 5ppg (pit, not returns), drilled solids < 50% and < 30ppb Avoid too much steering which leaves ledges Clean boats, rig piping, pumps, shakers and pits Pickle running string and washpipe Minimise time between TD and screens on bottom for shale clock (3-4 days to do all the stiff wiper trip, casing clean-up and RIH practices) Circulate open hole to RDIF with zero solids (i.e. same shale stabilisers, same viscosity, same weight to keep hole diameter) Clean casing to < 0.01% solids in brine returns (not just NTU) Make-up all screen using dope-free ideally, or 1 paint brush doping pin-end only (screen, wash-pipe, work-string) Hold acid treatment against sand face to soak filter-cake by holding wellbore static with seals in sealbores 24

DIF Quality Control 100.0 Solids Conc in Active System (Initial CaCO3 = 52 ppb; Dilution Rate = 0 bbl/ft) 90.0 80.0 Modelled CaCO3 Measured CaCO3 Modelled Drill Solids Measured Drill Solids Solids Conc (ppb) 70.0 60.0 50.0 40.0 30.0 20.0 10.0 0.0 0 200 400 600 800 1000 1200 1400 1600 1800 2000 Horizontal Length (ft) 25

14 Impact of DIF Quality on Filtercake Cleanup MBT or Drill Solids Conc. (lbs/bbl) 12 10 8 6 4 2 Good Removal Poor Removal 0 8000 9000 10000 11000 12000 MBT in Pit Drill Solids @ Bit MD (ft) 26

Sand Control Best Practices Production Start-up Limit drawdown Gradual choke opening Production or reservoir engineer witness offshore to influence, observe, record and react Repeat for re-starts following first few production trips 27

Lessons Applied New Field 1. Sand control selection practices followed 2. Sand control design practices followed 3. Sand control manufacturing quality practices followed 4. Sand control installation practices followed in procedure, and in practice 5. 60-80 metre screens will avoid plugging and erosion due to lower rates/metre 6. 60-80 metre screen mesh intervals are less sensitive than last wells to anything less than ideal practice at every stage 7. Annular gap minimised, which has much bigger effect than good / bad practices 8. Screen mesh sized for very large D 10 sand size 9. Run screens in clean brine < 0.01% solids 10.Avoid plugging screens by keeping shales from swelling 11.Ensure acid treatment effective by testing, uncontaminated filter-cake, good placement & exposure time to filter-cake 28

Sand Control Best Practices Key Points Summary Core samples for sand strength Long screens, large OD screens D 10 particle size screen pre-selection & test Soluble filter cake by lab testing & QC during drilling & completion operations Prevent shales swelling (RDIF shale inhibitors, shale avoidance, exposure time) Clean pits, pumps, pipes, shakers, brine and pickle running string & wash-pipe 29

Sand Control Best Practices 90 Industry Completion Failure Data Data for OH Completions with Stand-Alone Screens Completion Failure % 80 70 60 50 40 30 20 10 0 Highest Failure Rate for Major Operator: 15 Failures/19 Wells Average Failure Rate from Industry Database: 39 Failures/110 Wells Lowest Failure Rate of Major Operators: 4 Failures/71 Wells Industry Worst Industry Average Industry Best SPE 73772 An Evaluation for Screen-Only and Gravel-Pack Completions SPE 110082 Current State of the Premium Screen Industry: Buyer Beware. SPE 135294 Comparison of Inflow Performance and Reliability OHGP and OHSAS Completions 30