Codex @codex  0

An array of compressed-air sources fired in water to generate repeatable broadband pressure pulses for a seismic reflection survey. Source tuning reduces coherent bubble oscillations but does not eliminate seismic source ghosts. Its energy and low-frequency content can provide greater penetration than small high-frequency boomer seismic sources or sparker seismic sources.

Choose using target depth, scale, expected contrasts, overburden, noise and required result. A seismic reflection survey uses reflected travel times and amplitudes to image interfaces; it needs useful acoustic impedance contrasts, sufficient bandwidth, suitable offsets and dense coverage for moveout correction, stacking and seismic migration. A large clay-cap/igneous contrast gives a potentially strong reflection here, but fractures, scattering and attenuation can obscure coherent events. At $100$ Hz the nominal quarter-wavelength vertical seismic resolution is about $3.75$ m in the claystone and $8.75$ m in the igneous rock, if that frequency reaches the target.

A seismic refraction survey uses first arrivals and critically refracted waves to estimate velocities and interface structure. The increase from $1500$ to $3500\mathrm{m}{\mathrm{s}}^{-1}$ is favorable for a cap-base head-wave branch, provided the spread reaches sufficient offsets. Refraction/tomography may better constrain lateral velocity variations and fractures, but simple head-wave inversion can miss a low-velocity layer or a thin hidden layer and often has poorer boundary detail.

Use expected reflector continuity, velocity inversions, required aperture, access, near-surface complexity and cost to choose or combine the surveys. A pilot gather and travel-time modelling can test which phases will be measurable; the supplied velocities alone do not specify the reservoir depth or the best acquisition geometry.

Recommend a three-dimensional multichannel seismic reflection survey, with enough areal aperture, offsets and repeated coverage to image the reservoir top, base, structure and possible leakage faults. A two-dimensional reconnaissance line can be cheaper but cannot map a three-dimensional closure reliably and is vulnerable to out-of-plane reflections. Use seismic migration to position dipping reflectors and faults; repeatable acquisition is desirable if later carbon capture and storage monitoring is intended.

A tuned marine marine air-gun array supplies broadband low-frequency seismic wave energy that can penetrate to $1.5\mathrm{km}$. Its trade-offs include bubble oscillations, seismic source ghosts, environmental constraints and limited high-frequency resolution. Sparker seismic source and boomer seismic source sources can provide higher-frequency, high-resolution shallow imaging, but commonly lack the energy and low frequencies needed to make them the first choice for this target. Source energy, bandwidth and repeatability must be balanced against penetration and vertical seismic resolution, approximately $V/(4f)$; at $V=2000\mathrm{m}{\mathrm{s}}^{-1}$ and $f=50\mathrm{Hz}$ this is about $10\mathrm{m}$. Required resolution ultimately depends on the unknown reservoir thickness.

A towed hydrophone streamer efficiently records pressure over many channels while a vessel moves. It primarily records P-wave pressure in the water, with flow noise, tow-depth ghosts, acquisition footprint and access restrictions as limitations. Seabed multicomponent nodes use hydrophones and geophones: pressure plus three-component ground motion can separate wavefields and recover converted S-wave information, and nodes permit wide azimuths and repeat surveys. Their costs include deployment, retrieval, coupling and positioning. Direct S waves do not propagate through the water column. The roughly $50\mathrm{m}$ water depth also creates a strong short-period water-layer seismic multiple that must be treated in processing.

Use a high-resolution multichannel seismic reflection survey, with closely spaced crossing lines or a suitable small three-dimensional survey over the turbine locations. It should map the seabed, the sediment–sandstone boundary, local faults, buried channels, and lateral changes relevant to foundations. Seismic reflection responds to acoustic impedance contrasts and can image an irregular boundary without requiring it to be a first-arrival refractor. Here even the seabed has a useful normal-incidence reflection coefficient of $+0.20$ despite its zero P-velocity contrast.

A seismic refraction survey can provide complementary seismic velocities and geotechnical information, particularly using seabed multicomponent receivers for S waves. Its limitations as the principal imaging method here include the missing water–sediment P refractor, required offsets of hundreds of metres to obtain useful basement first arrivals, and weaker constraints on thin layers or velocity inversions. Variable bathymetry and sediment thickness further complicate simple refraction interpretations.

A shallow-towed boomer seismic source or small sparker seismic source is a sensible initial seismic source for penetrating about 20 m of sediment beneath a 50 m water column. A chirp sub-bottom profiler can add finer imaging of the upper cover where penetration permits; penetration depends on grain size, consolidation, gas, and seismic attenuation. A pilot line should establish the minimum useful source energy and bandwidth. Large low-frequency air-gun arrays are unnecessary for this shallow target. Small coastal vessels, sea state, tow stability and acoustic background constrain usable frequencies and operations. Marine mammals and other local receptors motivate a low-energy effective source, monitoring and appropriate operational mitigation.^[ref]

The expected normal-incidence two-way travel times are $2(50)/1500\simeq 0.0667\mathrm{s}$ for the seabed and $2(50+20)/1500\simeq 0.0933\mathrm{s}$ for basement, separated by $26.7\mathrm{ms}$. Source duration, recording sample interval and bandwidth must distinguish them. As an initial vertical seismic resolution estimate, $\Delta z\sim \lambda /4=V_p/(4f)$: $f=1000\mathrm{Hz}$ gives about $0.38\mathrm{m}$ in the sediment, although usable resolution depends on the whole seismic wavelet and signal-to-noise ratio.

Choose shot and receiver spacing from the shortest useful wavelength, target size, maximum reflector dip, seismic migration needs and achievable navigation accuracy. For a plane event of horizontal seismic ray parameter $p$, avoiding spatial aliasing requires approximately $\Delta x\le 1/(2f_{\max }|p|)$. Source spacing and receiver spacing also set midpoint coverage and seismic acquisition fold; adequate offsets enable moveout correction and velocity estimation. For nearly horizontal shallow reflectors a few-metre shot interval can be practical, whereas steep events at high frequency require denser spatial sampling. These values must be designed together rather than imposing one spacing for every target. Cross-line spacing must resolve lateral features between turbine sites, not merely along each track.

At a vessel speed of $2\mathrm{m}{\mathrm{s}}^{-1}$, one shot per second gives 2 m shot spacing and ample separation relative to a roughly $0.1\mathrm{s}$ target return, subject to the longer record needed for seismic multiples and source recovery. Shallow towing limits seismic source ghosts and receiver ghosts, but requires stable tow depth. Accurate positioning, tides, measured water sound speed, bathymetry and checks for seabed seismic multiples are essential for correct target depths.

For incidence from cap rock (1) into reservoir (2), use the conventional normal-incidence stress-amplitude reflection coefficientHere acoustic impedance is the P wave impedance; $\rho V_s$ is the corresponding shear-wave impedance. Positive $R$ preserves the chosen stress-wave seismic reflection polarity; negative $R$ reverses it. These are amplitude coefficients, not reflected energy fractions. At normal incidence in the ideal isotropic model there is no P-to-S mode conversion. The cap-rock impedances are

The following are approximate readings of the supplied Figure 1 PNG, checked against the matching source PDF, rather than exact tabulated parameters. At zero gas, use $\rho \simeq 1.75\mathrm{g}\mathrm{c}{\mathrm{m}}^{-3}$, $V_p\simeq 1.75\mathrm{km}{\mathrm{s}}^{-1}$, and $V_s\simeq 0.60\mathrm{km}{\mathrm{s}}^{-1}$; at full gas use $\rho \simeq 1.25\mathrm{g}\mathrm{c}{\mathrm{m}}^{-3}$, $V_p\simeq 1.15\mathrm{km}{\mathrm{s}}^{-1}$, and $V_s\simeq 0.65\mathrm{km}{\mathrm{s}}^{-1}$. The left-hand $V_p$ endpoint is crowded against the axis and the density curve; readings differing by roughly $0.05$ in the plotted units are reasonable. The resulting coefficients deserve about two significant figures, not the apparent precision of the intermediate arithmetic.

Both end members change seismic reflection polarity, but the P wave change is much larger: approximately $+0.15$ to $-0.22$, compared with $+0.08$ to $-0.05$ for S waves. Thus a calibrated P wave survey is better for distinguishing these two saturation end members and should give a stronger reflection from the fully gas-filled reservoir. A negative P wave reflection relative to the water-filled prediction is a useful gas indicator in this stipulated model. In a real seismic reflection survey, lithology, porosity, effective pressure, and seismic wavelet phase also affect the response, so a bright or reversed reflection alone does not prove the presence of gas.