Polymer Flooding Pilots: Why, How, What to Measure, and When to Scale

Introduction

A well-designed polymer flooding pilot is the most reliable way to de-risk a chemical EOR project before committing to full-field rollout. Laboratory work and numerical simulation cannot fully predict in-situ injectivity, pressure behavior, polymer propagation, produced-fluid handling, and operational realities in heterogeneous reservoirs. A short, instrumented field pilot closes these gaps by validating injectivity at target viscosity, confirming connectivity and conformance, quantifying retention and breakthrough behavior, and stress-testing logistics and QA/QC at industrial scale. The pilot’s decision gates are built around clear KPIs—incremental oil, injectivity (PV/year) at target resistance factor, viscosity compliance, produced-polymer trends, and model match quality—so that scale-up becomes an execution step rather than a leap of faith.

Why a Pilot Is Often Recommended

Best-in-class 3D simulation and lab programs cannot predict injectivity, pressure barriers, near-wellbore behavior, field retention, and dilution during water chase. Heterogeneity is always underestimated and legacy waterflood history create preferential flow paths and crossflow that are difficult to capture without field observation. Moreover, produced-water chemistry, plant hydraulics, and operational uptime materially affect polymer viscosity compliance and ultimate recovery; these are facility- and crew-specific factors that only a pilot can reveal. In practice, many historical failures stem from issues that a pilot would have identified early: poor water quality, too-low injected polymer concentration, severe heterogeneity or fractures, excessive resistance factor leading to unacceptable injectivity decline, or retention far above expectations.

Pilots also validate the supply chain. Full-field polymer floods can require 10,000–50,000 t/y of polymer (up to ~2,500 containers at 20 t each). Confirming sourcing redundancy, storage, transfer, and road/rail constraints at pilot scale prevents later stoppages. Offshore and remote settings amplify this benefit.

Start with the end in mind: if roads, rail, tankage, or offshore transfer windows cannot support expansion, address these constraints before the pilot or explicitly scope the pilot as a feasibility test for the supply chain.

Field-First Design Philosophy

Design starts in the field—not in the lab. Before selecting chemistry or running detailed corefloods, gather the contextual information that determines feasibility and test scope: water sources and quality, logistics (roads, rail, warehousing), well completions, injectivity history, spacing and thickness, and current facility constraints. These inputs define which lab tests are truly needed, at what salinity and temperature, and at which shear conditions, so your bench program is representative and efficient.

Water composition governs polymer choice and stability; quality (oil-in-water, solids, bacteria, oxygen) governs filtration, biocide regime, and how much you can inject sustainably. Establish whether salinity will vary over time, whether contaminants or treatment additives interact with the polymer, and whether the available volumes are sufficient for the planned pilot duration.

Pilot objectives and KPIs

Define what success means—before pattern selection; it will help clarify with your management what is expected. Objectives differ in tertiary vs. secondary mode and should be specific and measurable:

Injectivity & pressure envelope at target polymer viscosity (PV/year ≥0.1 as a practical lower bound for viable response at typical spacings).
In-situ resistance and retention via calibrated fall-offs, produced-concentration tracking, and tracer timing to validate model parameters.
Incremental oil (rate acceleration vs. recovery uplift), oil cut increase, and response timing by well.
QA/QC compliance across preparation/mixing/injection, injection uptime.
Viscosity compliance: ≥90–100% of target over the injection period, with root-cause analysis for deviations (mixing, oxygen, temperature, downtime).
Model match quality: ability to simultaneously reproduce pressure, injectivity, produced-polymer, and oil response with pilot-calibrated parameters, not lab priors alone.
Produced-polymer trends: breakthrough timing, concentration envelope, and trend slope (rising, stable, falling) inform conformance needs; sub-~100–300 ppm is typically manageable at the plant with tuning, whereas persistently higher levels may signal high-perm channeling that warrants profile control.
Logistics readiness for expansion: supply continuity, storage/buffer capacities, transfer, road/rail constraints.

Candidate Area and Well Selection

Select a zone with high mobile oil saturation and constrained flow so that the polymer signal isn’t swamped by external interference. A five-spot with small-to-moderate spacing is often preferred (≤150 m); very large spacing delays response and raises retention risk, while extremely tight spacing can prompt early polymer breakthrough, especially after extensive prior waterflooding. Aim for good PV/year via the trio of spacing, net pay, and feasible rates (above 0.1 PVI/year); then confirm confinement, connectivity, and lack of disruptive adjacent activities during the baseline window.

Rework the subsurface picture with what you measure, not only what you inherited: step-rate tests (mindful of unconsolidated sands), pressure fall-offs, interference/pulse tests, and tracers to map connectivity and estimate parting pressure. If there is an active aquifer, plan higher injected viscosities or slugs at/above the OWC to slow encroachment; higher viscosity reduces dilution along the aquifer path.

Baseline the pattern before tertiary injection: stabilize rates, avoid simultaneous maintenance that perturbs voidage balance, and document pressures, WOR/WC trends, and any aquifer influence. Build a consistent, pre-pilot dataset so that polymer effects are distinguishable.

Injection Strategy: Viscosity, Polymer Choice, and Slug Size

Viscosity is the value driver. The operator pays for resistance factor (RF) that improves mobility ratio and sweep; target viscosity follows from mobility ratio needs and heterogeneity. Without reliable relative permeability, adopt conservative targets and validate in corefloods across representative permeability facies, recognizing that solution viscosity is not equal to in-situ RF. Underestimating heterogeneity predictably leads to early breakthrough and underperformance.

Polymer chemistry depends on water salinity and divalent content, reservoir temperature, permeability, and—critically—residence time. Hot reservoirs with short spacing may not require premium chemistry; cooler reservoirs with long residence times might. Pilot design should allow viscosity tuning in response to pressure barriers, injectivity limits, or viscosity-compliance deviations.

Slug size matters. Slug size matters for the water-chase phase: very small slugs are prone to dilution and water fingering, undermining sweep as soon as water resumes. While practices vary, many successful designs inject on the order of ~30–60% PV or more (field examples span ~50–100% PV), with the rationale to maximize sweep, compensate for retention, and maintain mobility control deeper into the pattern. The slug will not propagate and remain intact during subsequent water injection. Inject polymer until the extra oil produced doesn’t pay for the chemicals injected. For that reason, operational continuity is non-negotiable: intermittent water between polymer periods (unplanned WAP) can disturb the oil bank and reduce compliance with the planned viscosity profile, immediately showing up in mass-throughput and oil-rate deviations. Design redundancy in pumps and storage to keep polymer on-spec and continuous.

Completions and Surface Facilities That Enable Success

Minimize shear in near-wellbore flow: design perforations or ICD/OCD hardware and rates to keep shear rates below damaging thresholds; re-perforate if legacy completions impose excessive contraction. For horizontals, selective injection hardware can steer flux away from thief zones and reduce early BT. On producers, sand control and appropriate artificial lift protect uptime and mitigate carry-under of polymer into hot ESPs that can overheat and encourage precipitation.

On the surface, robust injection water treatment (nutshell filtration, biocide, scale and corrosion control), oxygen management, leak-free injection lines, and adequate mixing/skid design are non-negotiables. The pilot is the proving ground for viscosity compliance: sub-spec mixing, oxygen ingress, or intermittent water injection will show up immediately as viscosity dips and step-outs in oil rate versus plan.

Surveillance and Diagnostics: Build an Evidence-Rich Pilot

A pilot succeeds or fails on the strength of its surveillance. Establish a steady baseline, then run a structured program:

Well tests: step-rate (with caution in unconsolidated formations), fall-off to infer injectivity index, skin and apparent viscosity in the near-wellbore; interference and pulse tests for connectivity and pressure communication.
Tracers: quantify interwell connectivity and transit times; align patterns and detect out-of-zone flow or thief pathways.
Production diagnostics: WOR/WC vs PV injected, GOR and trends on offset wells to flag fractures, aquifer encroachment, or crossflow.
Logs and profiles: periodic ILT/PLT to map layer-by-layer conformance and observe redistribution as polymer advances; saturation logging if SP/ASP elements are involved.
Viscosity compliance: track injection-side viscosity and produced-side polymer concentration to understand retention, mixing, and breakthrough dynamics; install downhole pressure gauges where feasible to decouple tubing from formation signals

Scaling from Pilot to Full-Field

The pattern is representative of field statistics (permeability, thickness, saturation, heterogeneity), or you can map pilot-derived parameters to specific facies across the field static model.
For simulation fans, a calibrated model exists that reproduces pilot pressures, injectivity, produced-polymer concentrations, and oil response with a single set of physics and parameters, then generalizes to neighboring patterns.
Logistics are executable at scale: confirmed polymer sourcing with redundancy, reliable storage and transfer, trained operators, and an injection plant that holds viscosity within spec. Scale plans should quantify annual tonnage, buffer capacities, and transportation cadence.
Facility readiness is proven: produced-water systems handle expected polymer carryover without sustained upsets; corrosion, scale, and oxygen are under control; lift systems operate within envelopes as total liquids and viscosities evolve.
Governance and budgeting are aligned: policy for when to continue, step-up, or pause polymer based on annual KPI review (“inject until incremental barrels no longer pay for polymer”), with flexibility to retarget viscosity or patterns as learning accrues.

Rollout should proceed in waves across look-alike patterns while maintaining the pilot’s surveillance discipline: periodic fall-offs, viscosity compliance checks, produced-polymer trending, and selective ILT/PLT campaigns to sustain conformance. Where aquifers are active, favor higher viscosities and carefully manage contact with the OWC to delay dilution and breakthrough.

Extension often proceeds in phases with modular units to target sweet spots and keep flexibility while minimizing CAPEX.

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