Surfactant EOR · HTHS carbonates

Does retained surfactant fit the screening budget?

High-temperature, high-salinity carbonates destabilize surfactants and raise retention. This companion implements the retention-controlled screening framework that links laboratory surfactant performance to field incremental recovery for a surfactant-only GAC/IOS blend, designated SF4: stable for 30 days at 120 °C, a Winsor III window between 30 000 and 60 000 ppm with S* = 46 000 ppm, σ_os = 1.93 × 10⁻³ mN·m⁻¹ at 100 °C, and corefloods that mobilized 76.1 % and 86.4 % of S_orw at a final dynamic retention of 0.16–0.17 mg·g⁻¹. At the scenario specified in Section 2 the transform returns RF_inc = — and a retention cost C_ret = —, which — the B_max = — screening ceiling, against a total unit technical cost of — and a net margin of —. Retention reduction toward 0.10 mg·g⁻¹ remains the main field-translation lever for this surfactant-only HTHS carbonate case.

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Retention cost C_ret · USD/inc. bbl

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RF_inc · % OOIP

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Total UTC · USD/inc. bbl

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Gate margin B_max − C_ret

Interactive companion to the manuscript A retention-controlled screening framework for chemical EOR in high-temperature, high-salinity carbonate reservoirs — prepared for submission to Petroleum Exploration and Development, pending ADNOC review.

MANUSCRIPT PDF DATA WORKBOOK

Scenario record

Prepared by

Imad A. Adel

Subject

Surfactant EOR · HTHS carbonates

Basis

SF0–SF4 formulations · corefloods A10 + SN7 at 100 °C · 2026

Scenario status

BASE CASE

Summary of results — current scenariobase case

Retention cost C_ret

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Gate margin

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RF_inc

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Retained mass M_loss

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lb per inc. bbl

Total UTC

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Net margin

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HOW TO USE

What this is: An interactive implementation of the retention-controlled screening framework developed in the accompanying manuscript (prepared for submission to Petroleum Exploration and Development, pending ADNOC review), downloadable from the link in the header. The page opens on the manuscript base case — Γ = 0.170 mg/g-rock, P_s = 1.50 USD/lb, E_v = 0.60, R_lab = 86.4 % of S_orw — and the status field reads BASE CASE until an input changes.
Parameters: Every input lives in Section 2. Retention Γ, surfactant price P_s and sweep efficiency E_v carry sliders at the top of that section; the recovery basis, the economic frame and the four base unit-technical-cost rows are entered numerically.
Measured data and live model: Sections 3 to 6 report measured laboratory data and do not change with the inputs. Sections 7 to 10 recompute from Section 2 on every edit: the recovery transform, the retention-cost gate, the unit technical cost stack, and the two C_ret maps.
Figures are interactive: Hover for exact values, drag to zoom, double-click to reset the axes, and use the camera icon to download a PNG.
Export and reset: Export scenario downloads a text file of all inputs and computed outputs at full precision. Reset base case restores the manuscript values.
Where things are: Governing equations and screening constants in Section 1, parameters in Section 2, measured data in Sections 3 to 6, screening outputs in Sections 7 to 10, assumptions and limitations in Section 11.

Section 01 · Basis and formulation program · SF0–SF4 · 100 °C

Basis and formulation program

Five formulations (SF0 to SF4) were screened for 100 °C service at seawater-injection salinity (43 373 ppm TDS). Each pairs a Guerbet alkoxy carboxylate primary surfactant with internal olefin sulfonate co-surfactants and an ethoxylated phenol co-solvent at 1.0 wt % total active surfactant. Introducing a higher-chain IOS shifted optimum salinity from 88 kppm TDS in SF0 to about 46 kppm TDS in SF4, which aligns with the seawater-injection salinity path. SF4 was carried into two dynamic corefloods at 100 °C: A10, an Indiana limestone outcrop plug, and SN7, a reservoir carbonate plug, each run as a 5 PV seawater pre-flush, an SF4 slug injected at seawater salinity to zero oil cut, and a stepwise salinity-gradient post-flush from 43 373 to 20 000 to 10 000 ppm TDS. SN7 supplies the base case for field screening because it uses reservoir rock.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Stage A — Volumetric upscaling

Laboratory tertiary recovery is reported as a fraction of S_orw. Field screening requires incremental recovery on an OOIP basis, so R_lab is scaled by the maturity ratio S_orw/S_oi and the volumetric sweep efficiency E_v, and capped at the technical limit RF_tech.

Stage B — Retention pricing

C_ret prices the surfactant mass retained on rock after the post-flush material balance, per incremental barrel. It excludes mobile surfactant in the produced stream, polymer and alkali costs, water handling, and facilities.

Stage C — Gate and cost stack

The retention budget B_max gates field translation, and the inversion of the retention-cost relation returns the maximum allowable retention Γ_max for a given budget. C_ret then enters the unit technical cost stack against the screening oil price. At the current scenario C_ret = — and Γ_max at B_max is —.

Governing equations — screening data pack, 2026

Screening constants (not editable). K = 13.408 is the lumped constant in C_ret = K · Γ · P_s / E_v. Γ_r,max = 0.179 mg/g-rock, C_ret,base = 5.69 USD per incremental bbl, P_s,base = 1.50 USD/lb, RF_inc,base = 25.9 % OOIP and M_loss = 3.79 lb per incremental bbl are the calibration anchors of the two Γ_max forms. K is a rounded derived calibration constant: the manuscript base values (C_ret = 5.69 via M_loss = 3.79) and the continuous model K · Γ · P_s / E_v = 5.6984 agree within 0.15 %, which does not change the gate outcome at B_max = 6.0 USD per incremental bbl. Displayed values carry one decimal (Γ_max three); the scenario export carries full precision.

Section 03 · Phase behavior · measured · 100 °C

Phase behavior

Salinity-scan experiments were aged at 100 °C for two weeks and read for phase volumes. SF4 formed a Winsor Type III window from 30 000 to 60 000 ppm TDS, and the intercept of the water and oil solubilization trendlines places optimum salinity at S* = 46 000 ppm with R* = 12 cm³/cm³. The aqueous stability limit of 75 000 ppm at 100 °C provides a 30 000 ppm buffer above the injection brine, so modest salinity and hardness excursions along the mixing path do not trigger precipitation during slug preparation and early propagation.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Fig. 1Winsor I → III → II · window 30–60 kppm · S* = 46 kppm · R* = 12 cm³/cm³

Fig. 1 — Solubilization-ratio salinity scan for SF4 at 100 °C. Water and oil solubilization ratios (cm³/cm³) against total salinity (kppm); the measured Winsor Type III window is 30 000–60 000 ppm, the dotted vertical is the seawater-injection salinity 43 373 ppm, and the star marks optimum salinity S* = 46 000 ppm with R* = 12 cm³/cm³. Points are measured; no value is fitted on this axis.

Derived phase-behavior parameters — SF4S* = 46 kppm

Formulation summary — SF1 to SF4 at 100 °C

Surfactant compositions — active-matter weight basis

Section 04 · Interfacial tension · measured 60–90 °C · extrapolated 100–120 °C

Interfacial tension

Spinning-drop measurements were acquired between 60 °C and 90 °C because of equipment thermal limits, and the values were extrapolated to 100 °C using a power-law regression, IFT(T) = a · T^b. The extrapolated IFT for SF4 at 100 °C and seawater salinity was σ_os = 1.93 × 10⁻³ mN·m⁻¹. The Huh correlation with C_Huh = 0.3 mN·m⁻¹ and R* = 12 yields σ* = 2.08 × 10⁻³ mN·m⁻¹ for SF4; σ* aligns with σ_os because seawater salinity closely matches S*. The two estimates diverge for SF1 and SF2, where the spinning-drop value is sampled well off optimum salinity.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Fig. 2power-law fit σ = a · T^b to 60–90 °C · R² ≥ 0.98 · silver dashed

Fig. 2 — Interfacial tension of SF1 to SF4. (a) Spinning-drop IFT (mN/m, logarithmic axis) against temperature at seawater salinity; filled markers are measured at 60–90 °C and open markers are extrapolated to 100–120 °C from the power-law fit, drawn as the silver dashed line, and the dotted vertical marks 100 °C. (b) Huh-correlation IFT at optimum salinity against spinning-drop IFT at seawater salinity, both at 100 °C, in mN/m.

Power-law trendline coefficients — IFT(T) = a · T^bfit to 60–90 °C

Section 05 · Wettability · ambient screening

Wettability

An oil-aged carbonate chip was submerged in either seawater or SF4, an oil droplet was dispensed onto the submerged surface, and the contact angle was read from the image. Each condition was repeated three times. The chip contact angle shifted from strongly oil-wet (161°, 171°) toward intermediate-wet (69°, 72°) after SF4 exposure. These ambient-condition tests provide qualitative, screening-level indications of surfactant-induced surface modification; they do not establish in-situ wettability or quantify relative-permeability shifts at reservoir temperature and pressure.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Fig. 3

Fig. 3 — Ambient-condition contact angle of oil-aged carbonate chips in seawater and in SF4. Individual points are the three replicates per condition, the bar is the reported mean in degrees, and the horizontal bands are the wettability zones of the screening convention: water-wet 0–75°, intermediate-wet 75–115°, oil-wet 115–180°.

Contact-angle summary — baseline seawater versus SF4

Section 06 · Corefloods · A10 · SN7 · 100 °C

Corefloods

Both floods ran at 100 °C, 1.4 MPa (200 psi) back-pressure and 0.25 cm³·min⁻¹, with the injected-PV axis offset by the 5 PV seawater pre-flush. SF4 was injected at seawater salinity until the oil cut reached zero, followed by the stepwise salinity-gradient post-flush. A10 reached 76.1 % of S_orw with S_orc = 7.20 % and Γ = 0.16 mg·g⁻¹; SN7 reached 86.4 % of S_orw with S_orc = 5.43 % and Γ = 0.17 mg·g⁻¹. Differential pressure returned toward baseline in both cores, indicating no sustained impairment over the measured interval. The dataset does not isolate permeability as the driver of the contrast between the two cores: permeability, mineralogy and net adsorption affinity, and initial S_orw covary.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Fig. 4SW pre-flush → SF4 slug → post-flush 20,000 ppm → step-down 10,000 ppm

Fig. 4 — Coreflood A10, Indiana limestone outcrop plug at 100 °C. Tertiary recovery (% of S_orw) and oil saturation (%) on the left axis and differential pressure (psi) on the right axis against cumulative injected pore volumes; dotted verticals mark the start of the SF4 slug, the start of the 20 000 ppm post-flush, and the step down to 10 000 ppm.

Core and flood properties — A10Γ = 0.16 mg/g-rock

Measured core and flood properties for coreflood A10.
Property	Value	Unit	Source

Fig. 5SW pre-flush → SF4 slug → post-flush 20,000 ppm → step-down 10,000 ppm

Fig. 5 — Coreflood SN7, reservoir carbonate plug at 100 °C. Tertiary recovery (% of S_orw) and oil saturation (%) on the left axis and differential pressure (psi) on the right axis against cumulative injected pore volumes; the secondary pressure peak during the post-flush is consistent with an additional mobilization event along the evolving in-core salinity path. SN7 supplies R_lab = 86.4 % of S_orw and Γ = 0.17 mg/g-rock to the screening base case.

Core and flood properties — SN7Γ = 0.17 mg/g-rock

Measured core and flood properties for coreflood SN7.
Property	Value	Unit	Source

Provenance. The property tables and both series are reproduced from the screening data pack. The manuscript text reports k_w = 27.0 × 10⁻³ μm² for the outcrop plug and 4.42 × 10⁻³ μm² for the reservoir plug; the two sources differ on permeability, and the pack values are shown here as delivered, without reconciliation. Recovery endpoints, S_orc, retention and baseline differential pressure agree between the two sources.

Section 02 · Scenario parameters

Scenario parameters

The specification below opens at the base case of the screening data pack (2026). Every field is editable, and Sections 7 to 10 recompute from these values. Retention Γ, surfactant price P_s and volumetric sweep E_v are the screening variables and carry sliders; the remaining fields are entered numerically. Temperature, salinity and permeability enter through the measured sections only, not as model inputs.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Screening variables — primary

Dynamic retention Γ0.170 mg/g

0.10target 0.10 · measured 0.16–0.170.28

Surfactant price P_s1.50 USD/lb

0.75markers 1.25 · 1.50 · 2.002.50

Sweep efficiency E_v0.60

0.40polymer-assisted sweep assumption0.80

2.1 · Screening variables

Parameter	Value ✎	Unit
Dynamic retention Γ		mg/g-rock
Surfactant price P_s		USD/lb
Sweep efficiency E_v		fraction

2.2 · Recovery basis

Parameter	Value ✎	Unit
Lab recovery R_lab (SN7)		% of S_orw
Maturity ratio S_orw/S_oi		fraction
Technical limit RF_tech		% OOIP

2.3 · Economic frame

Parameter	Value ✎	Unit
Retention budget B_max		USD/inc. bbl
Preferred budget B_perf		USD/inc. bbl
Screening oil price		USD/bbl

2.4 · Unit technical cost — base rows

Cost element	Value ✎	Unit
Facilities CAPEX		USD/inc. bbl
OPEX		USD/inc. bbl
Polymer, alkali, & cosolvent		USD/inc. bbl
Effective surfactant		USD/inc. bbl

Retained mass M_loss = K · Γ / E_v = — lb per incremental bbl · C_ret = — USD per incremental bbl · RF_inc = — % OOIP · base rows sum — USD per incremental bbl. The four base rows above are screening assumptions drawn from published SP and ASP cost benchmarks; the retention row is computed, never entered.

Section 07 · Recovery transform · live

Recovery transform

Field screening requires incremental recovery on an OOIP basis. S_orw/S_oi is the maturity ratio linking remaining oil after waterflooding to initial oil saturation, and E_v is the field volumetric sweep efficiency, treated as a conditional input dependent on polymer-assisted sweep rather than a measured outcome of the surfactant-only corefloods. At R_lab = — % of S_orw, S_orw/S_oi = — and E_v = —, the transform returns RF_inc = — % OOIP against a volumetric ceiling of — % OOIP even at R_lab = 100 %. Near that limit RF_inc is sensitive to E_v: at S_orw/S_oi = 0.50 and R_lab = 86.4 %, RF_inc falls from 25.9 % OOIP at E_v = 0.60 to 17.3 % OOIP at E_v = 0.40.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Fig. 6

Fig. 6 — Incremental recovery factor over the sweep–recovery plane. RF_inc = min(R_lab · S_orw/S_oi · E_v, RF_tech) in % OOIP, contoured over E_v = 0.40–0.80 and R_lab = 50–100 % of S_orw on a 120 × 100 grid; the flat upper region is the volumetric ceiling RF_tech. The dashed curve is the isoline at the current RF_inc, the amber star is the manuscript base case at (0.60, 86.4), and the open marker is the current scenario. Recomputes from Section 2.

Section 08 · Retention-cost gate · live

Retention-cost gate

A retention budget B in USD per incremental bbl sets the economic limit for retention-controlled screening. This work uses B_max = 6 USD per incremental bbl as the upper-limit gate on the retention penalty and B_perf = 4 USD per incremental bbl as the preferred early screen; both align with the retention target band of 0.1–0.2 mg·g⁻¹ reported for ASP processes. Inverting the retention-cost relation converts the budget into a maximum allowable retention Γ_max. At the current scenario Γ_max = — at B_max, against an operating retention of —.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Fig. 7

Fig. 7 — Maximum allowable retention satisfying the retention-cost budget. (a) Γ_max (mg/g-rock) contoured over surfactant price P_s = 0.75–2.50 USD/lb and budget B = 2–8 USD per incremental bbl at fixed RF_inc,base = 25.9 % OOIP; the diverging scale is centred on Γ_r,max = 0.179 mg/g-rock, the dashed line is that isoline, the dash-dot horizontal is the current B_max, the dotted verticals are the price markers 1.25, 1.50 and 2.00 USD/lb, and the amber star is the base case at (1.50, 5.85). (b) Γ_max against RF_inc in % OOIP for B = current B_max (solid), B_perf (dashed) and 8 USD per incremental bbl (dashed); the petrol fill is the region satisfying B_max, the grey band lies beyond the technical limit RF_tech, and the open marker is the current scenario. Recomputes from Section 2.

Gate verdict

At Γ = — and P_s = —, the retention cost is C_ret = — against B_max = —. —

Section 09 · Unit technical cost · live

Unit technical cost

Retention Γ drives C_ret linearly, so retention reduction is the dominant lever for widening screening margin and lowering unit technical cost. The stack below decomposes the per-incremental-bbl cost into facilities CAPEX, OPEX, non-surfactant chemical spend, effective surfactant, and the retained-mass penalty carried in C_ret. Lowering retention to Γ = 0.10 mg·g⁻¹ at base price and sweep reduces C_ret to 3.35 USD/bbl, freeing 2.34 USD/bbl inside the retention budget. At the current scenario the total unit technical cost is — against a screening oil price of —, leaving a net margin of —.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Fig. 8

Fig. 8 — Unit technical cost stack at the screening oil price, USD per incremental bbl. The four petrol bars are the base cost rows entered in Section 2, stacked; the red bar is the computed retention cost C_ret; the ink bar is the total unit technical cost and the closing bar is the net margin against the dashed oil-price line. Bar labels carry one decimal. Recomputes from Section 2.

Section 10 · Retention-cost maps · live

Retention-cost maps

The retention-cost screening links two coupled levers: Γ sets C_ret at fixed P_s, while E_v sets RF_inc and shifts the iso-cost contours. The maps below evaluate C_ret = K · Γ · P_s / E_v in the sweep–retention and price–retention planes, with the B_max and B_perf iso-cost boundaries drawn on both. SF4 sits inside the region satisfying B_max yet lies near the boundary; the position supports feasibility but demands retention reduction to protect against field variability. Strategies that reduce Γ widen the margin without requiring higher E_v.

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Fig. 9

Fig. 9 — Retention-cost maps, C_ret in USD per incremental bbl. (a) C_ret over sweep efficiency E_v = 0.45–0.75 and retention Γ = 0.10–0.275 mg/g-rock at the current surfactant price. (b) C_ret over P_s = 0.75–2.50 USD/lb and the same retention range at the current sweep efficiency; dotted verticals are the price markers. The diverging scale is centred on the current B_max, petrol below the gate and red above it; the solid line is the B_max iso-cost boundary and the dashed line is B_perf. The amber star is the manuscript base case at Γ = 0.170 mg/g-rock, the red star is the 0.10 mg/g-rock retention target, and the open marker is the current scenario. Recomputes from Section 2.

Section 11 · Assumptions and limitations

Assumptions and limitations

Prepared by Imad A. Adel · Senior Petroleum Research Engineer, Chemical & Petroleum Engineering

Assumptions and limitations