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1. Collect flowrates and bottom-hole pressure (BHP) which are normally available with permanent downhole gauges (PDG)
2. Data filtering
   1. Filter the data for overshoots
   2. Filter the BHP data with wavelet thresholding to reduce the noise
   3. Decimate the BHP data (usually 10:1 or 100:1)
   4. Translate the surface rates to downhole total rate q_t with account of BHP at any moment of time
   5. Synchronise total flowrate q_t variations with BHP variations
3. Primary Analysis
   
   1. Filter out shut-ins and hold drawdowns only
   2. Create material balance (BHP and Pe vs cum Q) and IPR (BHP vs q_t) diagnostic metrics over the drawdown history
   3. Identify the zones of constant productivity index (PI = const), Steady-states (SS) and pseudo steady-states (PSS)
   4. Assess dynamic drainage volumes V_e for all wells – this is a volume which well is currently draining with account of interference with other wells
4. Deconvolution
   1. Select the constant Productivity Index time segments
   2. Remove pressure data during shut-in periods except possibly few valuable (representative and similar to drawdown)
   3. Process PBUs PBUs to assess formation pressures
   4. Input formation pressure P_e as constrains for future future deconvolution
   5. Tune up the weights to match deconvolution trials with PBUs against DTRs DTRs
   6. In case of wells are sitting in the same homogenous reservoir compartment with no behind-casing complications then assume CTR are symmetric to further constrain deconvolution
   7. Perform multiwell deconvolution and  and QC
   8. Analyse the response and separate wells by non-interfering groups
   9. Repeat multiwell deconvolution for each well group and each constant TR time PI time period
5. Convolution and analysis
   1. Reconstruct formation pressure historyP_e history
   2. Reconstruct productivity index history history
   3. Validate if PI is  is constant and repeat deconvolution exercises over various time intervals if required
   4. Analyse rates correction and check if it is within the metrological limits and raise allocation concerns and/or advise the corrections
   5. Create unit-rate spider-plot – a pressure impact diagram showing how  one well with unit-rate would be varying the pressure in another well over time
   6. Create historical rates spider-plot – a pressure impact diagram showing how one well was varying the pressure in another well over time
   7. Create historical rates pressure interference map showing a current and cumulative impact from one well on another
   8. Create oil IPR at different formation pressure markups and analyse production optimisation potentials 
6. Analytical modelling 
   1. Perform analytical pressure diffusion modelling of all DTR/CTR wit  wit conventional Pressure Transient Analysis (PTA) using log-derivative log-log plots 
   2. Assess potential drainage volumes V_e,max for all wells – the volumes which well would be draining in case it would be the inly producing well in the field
   3. Assess well drainage and cross-well transmissibility and compare them against each other and against the OH  log interpretation on the map
   4. Analyse additional diffusion model parameters (skin-factor, fracture length, horizontal length, permeability anisotropy) against expectations
7. Additional studies
   1. Production forecasts
      1. Generate formation pressure and bottom-hole pressure forecasts based on NFA production/injection rates
      2. Generate formation pressure and production forecasts based on constant BHP
      3. Additional forecasts based on various BHP and production scenarios
   2. Numerical pressure tests
      1. Create N² numerical pressure test scenarios for each DTR and  and CTR
      2. Check  simulated DTR/CTR against  against deconvolved DTR/CTR in  in log-derivative diagnostic plots to understand where exactly numerical model may have discrepancies 
      3. Try various model boundaries, barriers and reservoir properties to improve the match
         
         

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