Topic 3.1 established that GK-22 has a total skin of +14, and Topic 3.2 confirmed this is entirely formation damage (Dq ≈ 0). Now the critical question: what caused that damage, how deep and how severe is the permeability alteration, and what can Hawkins' formula tell us about the magnitude and treatability of Sd?
In Topics 3.1 and 3.2, you established that the Gashaka GK-22 well has a total skin S′ = +14, that this is rate-independent (Dq ≈ 0.001), and that it is therefore entirely formation damage skin: S = Sd = +14. You also showed that this skin is costing 1,564 stb/d of production — 67% of the well's potential.
But what does Sd = +14 physically mean? Hawkins' formula gives us the answer: it connects the dimensionless skin number to two measurable physical quantities, the permeability ratio ks/k (how damaged is the near-wellbore rock?) and the damage radius rs (how deep does the damage extend from the wellbore?). These two parameters define the damage anatomy completely.
Understanding the damage anatomy is not academic: it directly determines whether acid can remove the damage (if ks is low due to clay swelling and filtrate invasion, acid targeting clay minerals is the answer) or whether mechanical intervention is needed (if the damage is cement-related or involves irreversible fines bridging beyond acid reach).
Formation damage is not a single phenomenon, it is a family of distinct mechanisms that all share one outcome: reduced near-wellbore permeability and increased skin. Identifying the correct damage mechanism is the prerequisite for selecting the correct treatment.
Piot & Lietard (Dowell Schlumberger, 1987) provided the most comprehensive taxonomy of formation damage types. They identified two fundamental categories:
Permeability impairment that originates within the formation rock matrix. Caused by: mud filtrate invasion, clay swelling/migration, scale deposition, organic deposits (asphaltenes, paraffins), water blocks, emulsion blocks, and wettability alteration. These can, in principle, be treated by correctly designed matrix acid, solvents, or surfactants.
Skin effects of mechanical or geometric origin that appear as damage but are not removable by acid. Includes: partial penetration (Sc), deviation effects (Sc″), rate-dependent turbulence (Dq), multiphase flow effects, and non-Darcy near-wellbore flow. Acid has no effect on pseudodamage. Covered in Topics 3.2, 3.4, and 3.5.
Damage can be introduced at any phase of the well's life. Each phase has characteristic damage types with characteristic permeability impairment patterns:
For the GK-22 well, drilled with water-based mud (WBM) through clay-sensitive Agbada Formation sands, drilling filtrate invasion is the primary damage mechanism. Two distinct damage processes occur simultaneously:
Particulate materials in drilling fluids (clays, weighting agents, lost-circulation materials) are forced into pore throats under overbalanced pressure. Permeability reduction of 60–90% is common. Limited radially to a few inches because mudcake forms rapidly. Very high ks/k contrast but very small rs.
Typical for WBM in GK-22 sands: ks/k ≈ 0.05–0.15, rs ≈ 0.5–1.0 ft from the wellbore
Liquid filtrate from WBM penetrates deeply into permeable formations. At GK-22's k = 85 md, filtrate invasion depth during an 18-day drilling operation could reach 10–15 ft. WBM filtrate disturbs clay equilibrium: smectite swells, kaolinite detaches and migrates, reducing permeability by 30–60%.
Typical for WBM in GK-22 sands: ks/k ≈ 0.30–0.50, rs ≈ 3–8 ft, deep but less severe than solids
Piot & Lietard classify the physical nature of damage into seven types. The choice of treatment fluid depends on the physical character of the damage, not its origin:
| Damage Type | Physical Character | Typical Treatment | Relevance to GK-22 |
|---|---|---|---|
| Emulsions | High-viscosity water-in-oil or oil-in-water emulsions blocking pore throats | Mutual solvents + de-emulsifiers | Possible from WBM filtrate + crude oil contact |
| Wettability change | Oil-wetting of formation surfaces, reducing kro | Mutual solvent + water-wetting surfactant | Risk if OBM surfactants present in mix |
| Water block | High water saturation near wellbore reducing kro | Surfactants or alcohols to reduce surface tension | HIGH RISK, WBM filtrate in oil-wet sand |
| Scales | Precipitated minerals (CaCO₃, BaSO₄, etc.) in perforations and pores | Depends on mineralogy: HCl, EDTA, HF | Possible from brine incompatibility during completion |
| Organic deposits | Paraffins or asphaltenes precipitated near wellbore | Aromatic solvents; hot oil | Possible at well pressures below asphaltene onset |
| Silts & clays | Migrated native fines bridging pore throats; swollen clay minerals | HF acid (mud acid) in sandstones | PRIMARY DAMAGE, kaolinite, smectite, chlorite |
| Mixed deposits | Organic + inorganic combined; common in mature fields | Dual-solvent system (hydrocarbon in acid) | Possible if asphaltenes present with scale |
The following drilling data from GK-22 informs the damage anatomy:
Mud system: Water-based mud (WBM), polymer/KCl inhibited. Mud weight: 12.0 ppg (slight overbalance above 11.1 ppg pore pressure gradient). Fluid loss: 6 mL/30 min (API standard, moderate). Mud solids content: 8% volume.
Drilling time in pay: 18 days from first sand entry to casing point. Extended time increases filtrate invasion depth significantly. Piot & Lietard Table 12-1 shows water mud filtrate can invade 30+ inches in 30 days in permeable sands; at k = 85 md, depth could be 6–12 ft.
Clay mineralogy (from cuttings XRD): Kaolinite 8–12%, smectite 3–5%, illite 2%, chlorite 1%. The kaolinite is the primary fines migration risk; smectite is the primary swelling risk in fresh filtrate contact.
Perforating: Overbalanced in KCl completion brine (1.15 sg). 4 spf, 0° phasing, 12g charges. No underbalanced surge. Perforation cleanup was limited, high probability of perforations partially plugged with debris and brine filter cake.
Formation testing: DST with 6-hour flow period at controlled drawdown, 8-hour build-up. Horner analysis: k = 85 md (consistent with core), S′ = +14.
Synthesis: The combination of (1) moderate-salinity WBM filtrate contacting smectite-bearing sand for 18 days, (2) overbalanced perforating plugging perforations with debris, and (3) KCl brine displacement without underbalanced surge is consistent with Sd of +10 to +16. The GK-22 measured S = +14 sits well within the expected range for this completion sequence.
Clay minerals in reservoir sands exist in a delicate electrochemical equilibrium with the formation brine, which is typically saline (15,000–100,000 ppm NaCl). When WBM filtrate (often 2,000–8,000 ppm KCl) contacts these clays, two mechanisms activate:
1. Smectite swelling: Smectite (montmorillonite) is an expandable clay that swells when contacted by low-salinity water. Swelling increases the clay platelet volume 3–10×, dramatically reducing pore throat sizes. Even 3% smectite content can reduce permeability by 40–70% when exposed to incompatible filtrate.
2. Kaolinite detachment and migration: Kaolinite is non-swelling but loosely attached to pore walls as stacked booklet structures. Low-salinity filtrate reduces the cation concentration surrounding the clay, weakening the electrostatic forces that hold kaolinite to the grain surfaces. The kaolinite booklets detach, migrate with the flowing filtrate, and bridge pore throats further from the wellbore. This fines migration permeability impairment is among the most severe and difficult to treat because the damage is distributed over a large radial volume.
KCl inhibition effectiveness: The KCl in WBM is intended to provide potassium cations (K+) that stabilise clay minerals better than sodium (Na+). However, at 2,000–4,000 ppm KCl, inhibition is only partial, particularly for smectite. Calcium-based muds or silicate-based muds provide better clay inhibition but were not used at GK-22.
Hawkins (1956) derived the definitive formula connecting the dimensionless skin number to the two physical descriptors of near-wellbore damage: permeability ratio and damage depth. Everything in formation damage quantification flows from this equation.
Hawkins conceptualised the near-wellbore region as two concentric zones of different permeability, each obeying Darcy's law independently:
Consider radial Darcy flow through the two-zone system. The pressure drop across the damaged zone (rw to rs) is:
The pressure drop over the same interval if no damage were present (ks = k) would be:
The excess pressure drop due to damage is the difference:
Using the definition of skin Sd = 0.00708 k h × Δpskin / (qμB):
The following table shows how Sd varies across the range of ks/k and rs/rw values typically encountered in field operations (rw = 0.35 ft):
| ks/k | Damage Severity | rs = 0.5 ft (rs/rw = 1.43) |
rs = 1 ft (rs/rw = 2.86) |
rs = 3 ft (rs/rw = 8.57) |
rs = 6 ft (rs/rw = 17.1) |
rs = 12 ft (rs/rw = 34.3) |
|---|---|---|---|---|---|---|
| 0.80 (mild) | ks 80% of k | 0.07 | 0.21 | 0.43 | 0.58 | 0.71 |
| 0.50 (moderate) | ks 50% of k | 0.17 | 0.52 | 1.08 | 1.44 | 1.77 |
| 0.30 (significant) | ks 30% of k | 0.39 | 1.21 | 2.52 | 3.38 | 4.12 |
| 0.15 (severe) | ks 15% of k | 0.95 | 2.96 | 6.16 | 8.26 | 10.07 |
| 0.10 (very severe) | ks 10% of k | 1.50 | 4.67 | 9.72 | 13.02 | 15.87 |
| 0.05 (extreme) | ks 5% of k | 3.18 | 9.90 | 20.60 | 27.58 | 33.61 |
In practice, we measure Sd from the well test and must infer (not measure directly) ks and rs. Hawkins' formula gives one equation in two unknowns — meaning there is a family of (ks/k, rs) combinations consistent with any given Sd. The engineering judgment is to identify the most physically plausible combination given the drilling and completion history.
In reality, most wells have multiple concentric zones of different damage severity. The total skin from multiple zones is additive, with each zone contributing independently:
For GK-22, a two-zone composite model is physically appropriate:
Zone 1 (rw to rs1 = 0.5 ft): Mud solids invasion, very severe (ks1/k ≈ 0.05–0.10). Contributes Szone1 = (10−1) × ln(1.43) = 9 × 0.36 = +3.2 to +5.7.
Zone 2 (rs1 to rs2 = 5 ft): WBM filtrate + clay swelling, moderate to severe (ks2/k ≈ 0.20–0.30). Contributes Szone2 = (4−1) × ln(5/0.5) = 3 × 2.30 = +6.9.
Total Sd ≈ 3.2 + 6.9 = 10.1 to 5.7 + 6.9 = 12.6, approaching but slightly below the measured +14, suggesting the filtrate zone may extend to 7–8 ft or the clay damage is more severe (ks2/k ≈ 0.15). Section 5 fine-tunes this model.
For completeness, here is how Sd from Hawkins' formula enters the full productivity index equation for GK-22:
Once Sd is reduced to +1 by acid treatment (Topics 3.6), the projected J would be: J = 1.380 × 7 / (7 + 1) = 1.380 × 0.875 = 1.208 stb/d/psi, a 2.63× production improvement from the acid treatment alone.
Hawkins' formula requires two inputs that cannot be directly read from a standard well test. This section provides the practical engineering tools to estimate both parameters from drilling records, mud properties, and core analysis.
The damaged permeability ks is the effective permeability of the altered zone. It depends on the damage mechanism and intensity:
| Damage Mechanism | Typical ks/k Range | Measurement Method | GK-22 Applicability |
|---|---|---|---|
| Mud solids invasion (WBM, 3–12 in) | 0.05–0.15 | Core flood with mud filtrate; SEM imaging | High — WBM used |
| WBM filtrate + clay swelling (smectite) | 0.10–0.30 | Core flood with formation brine vs filtrate | HIGH RISK — smectite present |
| WBM filtrate + kaolinite migration | 0.20–0.50 | Fines migration test; sequential flood test | HIGH RISK — kaolinite 8–12% |
| OBM filtrate invasion (gas reservoir) | 0.05–0.20 | Relative permeability to gas after oil invasion | Not applicable (WBM used) |
| Scale deposition (CaCO₃) | 0.05–0.30 | Scale analysis; X-ray CT scan of core | Possible if brine incompatibility |
| Cement filtrate | 0.30–0.70 | Cement filtrate pH test on core | Low (cemented above pay) |
| Asphaltene precipitation | 0.20–0.60 | SARA analysis; wettability test | Possible if below onset pressure |
| Perforation crushed zone (underbalanced) | 0.50–1.00 | Shoot & test (API RP-19B) | Low (overbalanced perforating) |
| Perforation crushed zone (overbalanced) | 0.05–0.30 | As above; confirmed by Piot & Lietard data | HIGH — OB perforating at GK-22 |
The damage radius is primarily a function of the invasion mechanism and the formation permeability. For filtrate invasion, the invasion depth increases with time and permeability:
For practical field estimation, the Simpson (1974) empirical data provides depth of invasion vs drilling time for different mud types:
| Time (days) | Oil Mud (ft) | Low-Colloid Oil Mud (ft) | Water Mud (ft) |
|---|---|---|---|
| 1 | 0.10 | 0.28 | 0.64 |
| 5 | 0.38 | 0.92 | 1.00 |
| 10 | 0.64 | 1.42 | 1.50 |
| 15 | 0.83 | 1.75 | 1.92 |
| 20 | 1.00 | 1.92 | 2.25 |
| 25 | 1.17 | 2.42 | 2.58 |
| 30 | 1.33 | 2.67 | 2.83 |
The most reliable approach to estimating ks/k is core flood testing under reservoir conditions. Relevant measurements include:
Clean core flood with reservoir brine under reservoir confining stress. Establishes the undamaged k for comparison. Must be at net overburden stress, not at ambient conditions.
Inject mud filtrate (at field pH, salinity, temperature) through the core at simulated downhole conditions. Measure steady-state permeability after damage: ks = kdamaged.
ks/k = kdamaged/kclean. Report as percentage return permeability. Values below 50% are considered significant; below 20% are severe and require treatment.
After damage, inject candidate acid system. Measure post-acid permeability: kacid. If kacid/ks > 3, the acid treatment is effective. This is the acid design test referenced in Topic 3.6.
Each phase of the well lifecycle introduces characteristic damage types at characteristic depths and severities. Understanding the timeline of damage introduction is essential for diagnosing accumulated skin and selecting the correct remediation strategy.
Drilling damage is introduced over the entire time the wellbore is open and in contact with the drilling fluid. It is usually the largest contributor to Sd because of the extended contact time and the deep filtrate invasion possible in high-permeability formations.
Mechanism: Particulate materials in the mud (clays, barite, lost-circulation materials) forced into pores by differential pressure. Pore bridging occurs when particle size ≈ pore throat diameter.
Typical depth: 3–12 inches from wellbore. Extreme damage (ks/k ≈ 0.05–0.15) but very shallow.
Treatment: Acid dissolves bridging particles if calcite/clay-based; mechanical action (perforation surge, back-surge) can dislodge debris. Filtercake removal is a critical pre-treatment step.
Mechanism: Liquid phase of mud penetrates formation under overbalance pressure. Filtrate alters native fluid saturations, clay chemistry, and wettability. In gas sands: water block. In oil sands with clays: swelling and migration.
Typical depth: 1–15+ ft depending on permeability and drilling time. In 85 md sands like GK-22, 5–10 ft is expected for 18 days drilling.
Treatment: Clay damage: mud acid (HCl/HF). Water block: surfactants or methanol. Depends on formation mineralogy and damage type.
Piot & Lietard state: “Perforating is always a cause of additional damage in formation rocks. Whether it is performed overbalanced or underbalanced, it always compacts the rock around the perforations and produces a zone with an average thickness of 0.5 in. (1 cm) where the permeability reduction averages 80%.”
Forces formation debris, gun debris, and fluid cake into perforation walls. Creates a crushed zone (ks/k ≈ 0.05–0.15, thickness ~0.5 in) AND packs the tunnel with debris. Effective ks/k for the entire perforation system may be 0.10–0.20. GK-22 was perforated overbalanced → this is a significant damage contributor.
The pressure surge draws formation debris and gun debris into the wellbore rather than packing it into the perforation. The crushed zone still exists (ks/k ≈ 0.50–0.80) but tunnel packing is eliminated. Net perforation skin is 3–5× lower than overbalanced.
Tubing-conveyed perforating with surge valves allows high underbalance (1,000–3,000 psi) and immediate pressure release into the wellbore. Achieves the best perforation cleanup. Crushed zone ks/k ≈ 0.70–0.95 in clean conditions. GK-22 would benefit significantly from TCP workover.
Between perforating and production, completion brine is typically resident in the wellbore for days to weeks. If this brine is not carefully filtered or is chemically incompatible with formation minerals or formation water, it introduces additional damage:
| Completion Fluid Issue | Damage Mechanism | Typical ks/k Contribution | Prevention |
|---|---|---|---|
| Suspended solids in brine | Particulate plugging of perforations & near-wellbore pores | 0.10–0.30 (additive with mud damage) | Filter to <2 μm; maintain <1 NTU turbidity |
| Incompatible brine + formation water | Scale precipitation (CaCO₃, BaSO₄, CaSO₄) at mixing front | 0.30–0.70 | Compatibility testing before fluid selection |
| Polymer residues (viscosified brines) | Gel blocking in pore network; resists clean-up | 0.20–0.50 | Use breakers; avoid high-polymer systems in pay |
| Corrosion inhibitors (oil-wetting surfactants) | Wettability alteration; reduce kro | 0.40–0.80 (affects kro not k) | Use water-wetting or neutral inhibitors |
| High-density brines (zinc bromide, CaBr₂) | Ion exchange on clay surfaces; crystallisation on cooling | 0.30–0.70 | Inhibited with pH control; careful design |
Even after successful completion, damage continues to accumulate during production. The most common production-phase mechanisms:
Unconsolidated native silts and clays detach from pore walls at high flow rates (critical velocity). Migrate with produced fluids and bridge pore throats near the wellbore. Progressive skin increase over months. Detected by increasing S′ on production logs.
As pressure drops from reservoir to wellbore, CaCO₃ and CaSO₄ become supersaturated and precipitate. Scale can block perforations and near-wellbore pores. Detected by rapid S′ increase correlated with water cut increase.
Heavy aromatic hydrocarbons precipitate below the asphaltene onset pressure (AOP). Deposits on pore walls and changes wettability to oil-wet. Seen in high-API gravity crude wells when pwf approaches AOP. Treated with aromatic solvents.
Estimating the contribution of each phase to GK-22's total Sd = +14:
| Phase | Mechanism | ks/k | rs | Sd contribution |
|---|---|---|---|---|
| Drilling (solids) | WBM solids plugging (r = 0.35–0.60 ft) | 0.08 | 0.60 ft | +4.4 |
| Drilling (filtrate) | Clay swelling + kaolinite migration (r = 0.60–5 ft) | 0.25 | 5.0 ft | +6.7 |
| Perforating (OB) | Crushed zone + debris packing | 0.20 | perf tunnel | +2.1* |
| Completion brine | Unfiltered KCl brine solids | 0.60 | 0.5 ft | +0.8 |
| Total Sd | +14.0 |
*Perforation skin contribution is estimated here using an approximate Hawkins model for the perforation tunnel geometry. Topic 3.4 provides the rigorous Sp calculation using Karakas–Tariq or Locke's nomogram.
This phased breakdown confirms that the drilling-phase damage (filtrate + solids) accounts for +11.1 of the total +14 skin. Acid treatment targeting the clay-related filtrate damage is the highest-value intervention, potentially reducing Sd by 8–10 units if the acid penetrates the full damage radius.
Applying Hawkins' formula to the GK-22 well to construct a fully quantified, self-consistent damage anatomy that explains the measured Sd = +14 and supports the acid treatment design in Topic 3.6.
Using the core flood result (ks/k = 0.145, representative average across the pay section), back-calculate the equivalent single-zone damage radius:
The single-zone model is a useful average, but the actual damage has two zones with different severity. Using the geological evidence and core data:
The damage anatomy directly informs the acid treatment design (Topic 3.6). Key conclusions from the GK-22 audit:
To treat Zone 2 (filtrate damage, r = 0.60 to 8.08 ft), the acid must penetrate 8 ft radius. Acid volume = π × (8.08² − 0.35²) × 42 ft × φ × overflush factor. At φ = 0.22: ~ 430 bbl acid required to fill the pore volume of the damage zone. Topic 3.6 refines this with spending calculations.
Zone 1 (solids): HCl preflush to dissolve carbonate cement and open pore throats before HF injection. Zone 2 (clay damage): 3% HCl / 2.5% HF mud acid to dissolve silicate clays. Core flood confirmed 76% permeability restoration with this formulation.
If acid restores ks to 76% of k throughout the damage zone (per core flood): New effective ks = 0.76 × 85 = 64.6 md. Post-acid Sd = (85/64.6 − 1) × ln(8.08/0.35) = 0.316 × 3.14 = +0.99 ≈ +1.0.
J ratio = (7 + 14) / (7 + 1) = 21/8 = 2.63×. At current q = 782 stb/d (drawdown = 1,700 psi), post-acid q = 782 × 2.63 = 2,057 stb/d. Additional production = 1,275 stb/d. This is the economic justification for the acid treatment presented in the Module 03 PBL solution.
The physical characteristics of the damage, not its origin, determine the treating fluid. Piot & Lietard identified seven physical damage types each requiring a specific chemistry. This section connects the GK-22 damage anatomy to the correct treatment approach.
The Piot & Lietard decision tree organises the seven physical damage types and their corresponding treatments. For GK-22, the primary damage is silts and clays:
| Physical Damage Type | Primary Treatment | GK-22 Relevance | Expected Sd Reduction |
|---|---|---|---|
| Silts & Clays (primary) | HCl preflush + HF mud acid (sandstone); HCl alone (carbonate) | HIGH, primary damage at GK-22 | 8–11 units (to Sd ≈ +1 to +3) |
| Water Block | Surfactants (reduce interfacial tension); alcohols (promote vapour) | MODERATE, WBM filtrate in oil sand | 2–4 units |
| Emulsions | Mutual solvents ± de-emulsifiers | POSSIBLE, WBM + crude contact | 1–3 units |
| Wettability change | Mutual solvent + water-wetting surfactant | LOW RISK at GK-22 | 1–2 units |
| Organic deposits | Aromatic solvents (xylene, toluene); hot oil | POSSIBLE, depends on crude composition | 1–3 units |
| Scales | HCl (carbonate); EDTA (sulfate); HF (silica) | LOW RISK, limited scale evidence at GK-22 | 1–5 units |
| Mixed deposits | Dual-solvent system (aromatic in acid) | LOW RISK, not confirmed by core analysis | variable |
Given the GK-22 damage anatomy, three intervention options are technically feasible. Selecting the optimal intervention requires comparing expected Sd reduction against cost and risk:
Target: Clay damage in Zones 1 and 2 (Sd contribution = +14)
Fluid: 5% HCl preflush (250 gal) + 3%HCl/2.5%HF mud acid (400 gal) + overflush (200 gal)
Expected result: Sd → +1 to +2 (based on core flood: 76% k restoration)
J improvement: 2.4× to 2.6×
Cost: Low to moderate (wireline/CT delivery)
Target: Perforation damage (Sd contribution = +2.1)
Method: TCP perforating with underbalanced surge at 800–1,200 psi UB pressure
Expected result: Sp reduction only; filtrate damage unaffected; net S′ improvement modest
J improvement: ~1.3× (from S = +14 to S = +12)
Cost: High (rig workover required)
Target: All damage categories simultaneously
Method: TCP reperforation to clean tunnels, then matrix acid through clean tunnels for maximum penetration
Expected result: Sd → 0 to −1 (clean tunnels allow acid to reach full damage radius)
J improvement: 2.8× to 3.1×
Cost: High but justified by additional uplift
Acid treatment effectiveness depends not just on whether the right chemistry reaches the damage zone, but on whether it has enough contact time to react with the damaging minerals. Clay dissolution kinetics are relatively slow compared to carbonate reaction:
Carbonates (HCl): React within seconds to minutes at reservoir temperature (120°F for GK-22). Effective at high injection rates.
Silicate clays (HF): React over minutes to tens of minutes at reservoir temperature. HF acid must be placed and soaked against the clay minerals for meaningful dissolution. Bullhead injection at high rates can pump the acid past the clay without adequate contact time.
Implication for GK-22: The mud acid (HCl/HF) should be placed at moderate injection rate (<0.5 bbl/min per perforation cluster) and allowed a 2–4 hour soak time before back-flowing. Wetting agents in the acid formulation will help maintain acid contact with clay surfaces in the mixed-wettability GK-22 sand.
Three interactive tools for Hawkins' formula: forward calculation, inverse back-calculation, and sensitivity analysis. GK-22 values are pre-loaded.
Ten questions covering Hawkins' formula, damage mechanisms, the GK-22 audit, and treatment selection. Score ≥ 8/10 before proceeding to Topic 3.4.
1. Hawkins' formula is Sd = (k/ks − 1) × ln(rs/rw). What physical condition produces Sd = 0?
2. Using the GK-22 canonical data (k = 85 md, rw = 0.35 ft, Sd = +14) and the core flood result (ks/k = 0.145), what is the back-calculated damage radius rs?
3. A well has Sd = +8 with ks/k = 0.20 and rs = 2.5 ft (rw = 0.35 ft). An acid treatment restores ks to 75% of k throughout the damage zone. What is the post-acid Sd?
4. According to Hawkins' formula, which factor has a larger effect on Sd: doubling the damage radius rs (at constant ks/k = 0.15, rw = 0.35 ft, rs from 2 ft to 4 ft) or halving the permeability ratio ks/k (from 0.15 to 0.075 at constant rs = 2 ft)?
5. The GK-22 well was drilled with water-based mud (WBM) containing KCl inhibitor and then perforated overbalanced. Using the Piot & Lietard classification, which physical damage type is the PRIMARY cause of the Sd = +14 skin?
6. A well has two concentric damage zones. Zone 1 (rw = 0.35 ft to rs1 = 0.60 ft): ks1 = 7 md, k = 85 md. Zone 2 (rs1 = 0.60 ft to rs2 = 5 ft): ks2 = 20 md, k = 85 md. What is the total Sd?
7. For the GK-22 two-zone damage model: Zone 1 (ks1/k = 0.08, rs1 = 0.60 ft) contributes Sd1 = +6.19 and Zone 2 (ks2/k = 0.25, rs2 = 8.08 ft) contributes Sd2 = +7.81. An acid treatment penetrates Zone 2 only (between 0.60 and 8.08 ft) and restores ks2 to 80% of k. What is the post-acid total Sd?
8. Which statement about the distinction between “true formation damage” and “pseudodamage” is CORRECT?
9. The GK-22 core flood (Section 3.4) showed that 3% HCl / 2.5% HF mud acid restored permeability to 76% of the original k on average across the pay section. If the acid treatment is designed and executed correctly, what is the expected post-acid Sd for GK-22? Use the single-zone equivalent model (ks/k = 0.145, rs = 3.77 ft, rw = 0.35 ft).
10. Based on the GK-22 damage audit (drilling filtrate damage as primary cause, core flood confirming mud acid effectiveness), which treatment sequence would deliver the MAXIMUM productivity improvement, and why?
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