What are the steps in conducting well stimulation?

At-a-Glance

Conduct well stimulation via a closed-loop workflow: candidate and diagnostics ? treatment design and execution plan ? HSE and equipment readiness ? step-rate/minifrac or injectivity test ? main treatment (pad/breakdown ? placement ? flush) ? controlled cleanup/flowback ? post-job evaluation and surveillance.

I. Objective Definition and Key KPIs

Assumptions (estimated): onshore vertical or moderately deviated oil/gas well; reservoir depth 2,000–3,000 m; stimulation type selected based on rock type (matrix acid for carbonates, HF/Mud acid for sandstones; hydraulic fracturing for tight formations).

• I.1 Objectives
  • 1.1 Reduce skin and increase inflow; connect more reservoir volume.
  • 1.2 Restore or exceed pre-damage productivity; mitigate near-wellbore damage or create conductive fractures.
• I.2 Core KPIs
  • 1.3 ?Skin (pre vs post), ?PI or ?IPR; production uplift (?q), water/gas cut stabilization.
  • 1.4 Treatment placement efficiency (e.g., proppant placed vs scheduled, diversion success), screen-out rate.
  • 1.5 Surface treating pressure conformance; NPT; execution time adherence; HSE (TRIR=0).
  • 1.6 $/incremental bbl (or $/Mscf) added; EUR uplift; emissions intensity during pumping.
  • 1.7 Integrity: no frac hit/offset communication, no sustained annulus pressure.
• I.3 Relevant Equations (performance and design)
  • 1.8 Radial flow with skin (field units): $$q_o=\frac{k h}{141.2\,\mu_o B_o}\cdot\frac{(p_e-p_{wf})}{\ln(r_e/r_w)+s}$$
  • 1.9 Skin benefit (rate ratio for same drawdown): $$\frac{q_{post}}{q_{pre}}=\frac{\ln(r_e/r_w)+s_{pre}}{\ln(r_e/r_w)+s_{post}}$$
  • 1.10 Step-rate/frac gradient: $$G_f=\frac{\Delta P}{\Delta D}$$ where ?P is pressure increment at onset of fracture and ?D is depth.
  • 1.11 Fracture net pressure: $$P_{net}=P_{bh}-P_{pore}-\sigma_{min}$$
  • 1.12 Fracture conductivity (dimensionless): $$C_f^D=\frac{k_f w_f}{k x_f}$$
  • 1.13 Pump horsepower (field): $$HP=\frac{Q\;(\mathrm{bpm})\times \Delta P\;(\mathrm{psi})}{40.8\;\eta}$$

II. Critical Parameters and Target Ranges

III. Step-by-Step Procedure / Workflow / Checklist

III.A Candidate Selection and Diagnostics

• 3.1 Compile data: logs, core, PVT, offset stim jobs, completions, production trends, pressure history.
• 3.2 Diagnose damage or need for fractures: skin from buildup/mini-DST; identify mechanisms (scale, fines, emulsion, water block, clay swelling, asphaltenes).
• 3.3 Select stimulation type:
  • 3.3.1 Matrix acidizing for near-wellbore damage in permeable rocks.
  • 3.3.2 Acid fracturing in carbonates when conductivity via etching is desired.
  • 3.3.3 Hydraulic fracturing in tight/ultratight formations to create SRV.
• 3.4 Lab/compatibility tests: brine/acid compatibility, precipitation checks, crude–acid emulsion tendencies, proppant pack damage, corrosion coupons.
• 3.5 Objectives/KPIs set: targeted ?skin (e.g., -6 to -10), ?q (e.g., +30–200%), execution window, screen-out risk =5%.

III.B Design and Engineering

• 3.6 Pressure window: confirm pore pressure, smin, caprock strength, MASP/MAASP; define max allowable treating pressure (ATP).
• 3.7 Perforation strategy: shot density, phasing, limited-entry sizing; ensure perforation friction 200–500 psi for even distribution.
• 3.8 Fluid system: choose base fluid and additives for temperature and damage control; set breaker loading to achieve <15 cP at BH temp by end of job.
• 3.9 Diversion plan: stages and diverter loading; for carbonates, alternating acid–diverter cycles; for multi-cluster fracs, limited entry + degradables.
• 3.10 Pump schedule:
  • 3.10.1 Matrix acid: preflush (HCl or solvent), main acid (HCl or mud acid), overflush; volumes 50–300 gal/ft depending on damage and rock (estimated).
  • 3.10.2 Hydraulic frac: pad ? slurry ramp (proppant concentration) ? tail-in ? flush; ensure proppant transport (velocity > settling), sandface rate above critical.
• 3.11 Power/hydraulics check: compute required HP using $$HP=\frac{Q\times \Delta P}{40.8\,\eta}$$ and verify pump spread capacity and friction pressure.
• 3.12 Integrity and barrier plan: BOP/packers tested, CT fatigue life, pressure tests (1.1× ATP), leak-off tests as applicable.
• 3.13 AFE, logistics, inventory: acids, additives, proppant, water/brine quality; waste and returns handling plan.

III.C Pre-Job Testing and Readiness

• 3.14 Pre-job HAZID/HAZOP; SIMOPS plan; permit to work; emergency response.
• 3.15 Step-rate test or injectivity test: determine closure/frac initiation; estimate $$G_f=\frac{\Delta P}{\Delta D}$$ and set treating pressure limits.
• 3.16 Mini-frac/DFIT (for HF): acquire ISIP, closure pressure, leak-off coefficient; calibrate model.
• 3.17 Mixing QA/QC: density, pH, viscosity, gel hydration, crosslink delay, friction reducer efficacy; sample retention for lab check.
• 3.18 Wellbore prep: cleanout, scale removal, solvent washes as needed; confirm perforation status and isolation (packer/plug/straddle).

III.D Execution (Pumping Operations)

• 3.19 Ramp to test rate; verify surface/bottomhole pressure response vs model; hold below ATP/MASP.
• 3.20 Breakdown/Pad:
  • 3.20.1 Matrix: Typically avoid fracturing; if pressure trends indicate fracture onset, reduce rate or divert.
  • 3.20.2 HF: Establish fracture with pad; confirm ISIP and net pressure trend $$(P_{net}=P_{bh}-P_{pore}-\sigma_{min})$$.
• 3.21 Main Placement:
  • 3.21.1 Acid: Execute preflush ? main acid ? divert cycles as designed; monitor rate/pressure; adjust acid strength or diverter on-the-fly for conformance.
  • 3.21.2 Proppant: Increase concentration per schedule; monitor sand rate, blender tub level, density; avoid sudden rate cuts that risk screen-out.
• 3.22 Flush/Displacement: Pump overflush (acid) or flush (HF) to clear tubulars; ensure proppant off-bottom and inside fracture.
• 3.23 Shut-in (if applicable): Observe pressure fall-off for closure (HF) or reaction time (acid systems).

III.E Cleanup, Flowback, and Normalization

• 3.24 Flowback under controlled choke; target drawdown to prevent fines/proppant backproduction; ramp per well integrity envelopes.
• 3.25 Sand management: install desander/sand traps; keep sand rates below threshold (e.g., =0.1 lb/MMscf or =50 ppm by mass) to protect facilities.
• 3.26 Chemistry returns: track iron content, pH, breakers, surfactants; adjust cleanup chemistry if emulsions or sludge observed.
• 3.27 Stabilize and hand over to production with surveillance plan.

III.F Post-Job Evaluation

• 3.28 Compare actual vs design: pad% variance, proppant placed, acid volumes, pressure match, screen-out events.
• 3.29 Estimate post-job skin from buildup or rate-transient; compute ?PI and ?q versus plan using: $$q=\frac{k h}{141.2\,\mu B}\cdot\frac{(p_e-p_{wf})}{\ln(r_e/r_w)+s}$$
• 3.30 Decide on remedial actions (e.g., additional diversion stage, refrac candidate flag).

IV. Risk & Mitigation (HSE, Reliability, Redundancy)

• 4.1 Screen-out / bridging
  • 4.1.1 Mitigation: Maintain sandface velocity; staged proppant ramp; viscosity/FR optimization; include contingency flush and rate increase protocol.
• 4.2 Out-of-zone growth / frac hits
  • 4.2.1 Mitigation: Real-time pressure matching; adjust rate/viscosity; reduce net pressure; observe offset pressure via DFIT gauges if available; set frac fence via perforation strategy.
• 4.3 Corrosion and precipitation
  • 4.3.1 Mitigation: Inhibitors per temperature; iron control; preflush/overflush to manage aluminosilicate/fluoride systems; monitor coupons.
• 4.4 H2S/CO2 exposure
  • 4.4.1 Mitigation: Sour service PPE, scavengers, appropriate metallurgy, gas monitoring; emergency blowdown plan.
• 4.5 Well integrity
  • 4.5.1 Mitigation: Verified pressure tests, two-barrier policy, temperature/pressure derating considered, packer setting check, vibration and torque control on CT.
• 4.6 Environmental/emissions
  • 4.6.1 Mitigation: Minimize flaring; optimize pump fleet utilization; low-emission power options when feasible; chemical containment and spill prevention.
• 4.7 SIMOPS/conflict
  • 4.7.1 Mitigation: Permit-to-work, radio channels, exclusion zones, crane lifts plan, hose management; stop-work authority affirmed.

V. Optimization Levers (Execution and Design)

• 5.1 Diagnostics-first: DFIT/mini-frac, step-rate, and fiber/pressure monitoring to calibrate model; update net pressure and closure on-the-fly.
• 5.2 Diversion effectiveness: Use pressure response to confirm diversion; if no step-up, increase diverter or switch method (particulate ? chemical).
• 5.3 Limited entry tuning: Adjust perforation friction 200–500 psi for cluster balance; validate via injection allocation (spinner or tracers).
• 5.4 Fluid economy: Optimize FR and gel load to minimum needed for transport; employ breakers tailored to BH temperature to reduce residual damage.
• 5.5 Drawdown management: Choke schedule to protect proppant pack and prevent fines mobilization; target early-time dP/dt limits.
• 5.6 Chemical tailoring: For sandstones, preflush with HCl or solvent; carefully meter HF strength to avoid secondary precipitates; for carbonates, staged HCl with inhibitors and diverters for deeper wormholing.
• 5.7 Execution analytics: Real-time pressure-rate match curves; track deviations >10% and trigger decision tree (rate, viscosity, stage length).
• 5.8 Logistics/maintenance: Hot redundancy on critical pumps/blenders; hose pressure ratings margin =15%; pre-job function tests reduce NPT.

VI. Verification & Monitoring Plan

• 6.1 Pre-job baselines
  • 6.1.1 PI/IPR, skin from buildup, PLT if available, water/gas cut, solids/salt content.
  • 6.1.2 Integrity logs/pressure tests; emissions/power baseline for OPEX/emissions KPI.
• 6.2 During job
  • 6.2.1 High-frequency rate/pressure/density/chem dosages; blender tub levels; sand concentration.
  • 6.2.2 Event tags: breakdown, ISIP, screen-out onset, diversion pressure steps, stage end times.
• 6.3 Immediate post-job
  • 6.3.1 Fall-off analysis for closure and leak-off coefficients; compare with model.
  • 6.3.2 Fluid returns sampling (iron, pH, residual FR/gel, oil–water emulsion index).
• 6.4 Flowback/early production
  • 6.4.1 Daily production test; choke, WHP, THP, sand rate, GOR/WOR; calculate early-time cleanup efficiency.
  • 6.4.2 If available: tracers or PLT to confirm stage/cluster contribution.
• 6.5 30–90 day evaluation
  • 6.5.1 Pressure transient or rate-transient analysis to quantify ?skin and fracture properties; update type curves.
  • 6.5.2 KPI scorecard: ?q, ?PI, cost/added barrel, screen-out rate, emissions per stage, lessons learned.