neqsim: Skill for Claude Code

Tight-reservoir test design and stage-gate screening

Reference implementation: task_solve/2026-10-09_ofc_rc7_shetland_chalk_further_development/step2_analysis/scripts (chalkmodel.py, econ.py, 04_fluid_compat.py, 05_economics_mc.py). Copy the pattern, not the numbers.

1. Order of work

1. Public evidence first (Sodir resource reports, field news, EAGE/SPE abstracts), saved to references/literature. Sodir FactMaps wellbore layers (204, 205) answer "which wells found hydrocarbons in formation X"; page with resultOffset and filter client side (the WAF rejects LIKE '%..%' filters).
2. Fluid from NeqSim: reservoir T, p, Psat (bubblePointPressureFlash), compressibility from density at p and p+10 bar, viscosity, Bo and GOR from a 3-stage flash, TVP of the stock-tank oil. These feed the well model.
3. Well model: 1-D slab from the fracture face to the drainage boundary (area = zones x 2 faces x 2 xf x h x effectiveness, length L). Use finite differences with scipy.linalg.solve_banded, geometric time steps (dt/t about 5 %), pressure-dependent mobility and piecewise compressibility (single phase above Psat, gas expansion below). Validate against the closed-form series q = A (k/mu) dP (2/L) sum exp(-(2n+1)^2 pi^2 eta t / 4L^2) and the identity RF = c_t dP / S_o.
4. Arps: fit the first-year window with free b, then extrapolate. A boundary-dominated well fitted in its transient window gives b about 1.4-1.7 and overstates EUR 2-2.4x (b = 1.0: 1.4-1.8x). Never book EUR from a test decline without a boundary or volume check.
5. Test duration from the radius of investigation r = sqrt(4 eta t), eta = k / (mu phi c_t); single phase above Psat, 4x smaller eta below. A 6-month flow plus two build-ups sees 200-340 m for k = 0.1-0.3 mD; k = 0.05 mD needs well over a year.
6. Flowback chemistry: acid (15 % HCl) reacts with CaCO3: 1 t HCl gives 1.37 t CaCO3 dissolved, 0.6 t CO2 and a spent brine of about 20 wt % CaCl2 (about 88 g/L Ca). Use AcidTreatmentSimulator for the cross-check and BrineMixingScaleEvaluator for mixing curves (formation water + seawater, + produced water, spent acid + produced water). BaSO4 is the first scale to watch when sulphate meets a barium-bearing water.
7. Hydrate: SRK-CPA with the associated gas, lumped C7+ and free water; Wax: the Pedersen model needs an n-paraffin distribution, P/A pseudo-components do not converge, so report wax as a lab-data gap.
8. Souring: bound H2S in gas by the fraction of injected sulphate reduced; SRB activity stops above about 80-90 C, so souring is a cooled-zone risk around injectors.
9. Value: annual cash flow with the 2022 NCS tax (78 % marginal, direct expensing), Monte Carlo with common random numbers, tornado, break-even EUR per well (scale the well curve until NPV = 0), break-even oil price.
10. Value of the test: bin the test-estimated EUR (lognormal error), take the best concept per bin, compare "test then decide" against "commit blind" and "do nothing"; sweep the measurement error. Make the test measure the candidate completion, not the old one.