Compressibility is a relative volume change of a fluid or solid in a response to a pressure change. We can relate this into a reservoir engineering aspect. Overburden pressure is rock weight and it typically has a gradient of 1 psi/ft. Rock metric and formation fluid in pore spaces supports the weight of rock above. When petroleum is produced from reservoir rocks, pressure of fluid in pore space decreases, but overburden is still the same. This will result in the reduction of bulk volume of rock and pore spaces. The reduction on volume in relation to pressure is called “pore volume compressibility (cf)” or “formation compressibility” and it can be mathematically expressed like this.
Vp = pore volume
dVp = change in volume
dp = change in pressure, psi
cf = rock compressibility, 1/psi
Note: The actual measurement of rock compressibility is expensive and it is required to have a formation sample. In practical, utilizing Hall correlation to determine rock compressibility is acceptable.
Hall’s rock compressibility correlation is a function only of porosity. The correlation is based on laboratory data and is considered reasonable for normally pressured sandstones.
Rock compressibility factor is very important for reservoir modelling.
cf is typically in the range from 3 x 10-6 to 6 x 10-6 1/psi.
Use the following data to determine volume change in reservoir rock per 100 psi of pressure drop.
Reservoir area = 2,000,000 square feet
Porosity = 15%
Rock compressibility = 3 x 10-6 1/psi
Formation thickness = 150 ft
Reservoir rock volume = 2,000,000 x 150 = 300 x 106 square feet
Vp = reservoir rock volume x porosity
Vp = 300 x 106 x 0.15 = 45 x 106 ft3
d Vp /dp = cf × Vp
d Vp /dp = 3 x 10-6 x 45 x 106 = 135 ft3/psi
dp = 100 psi
d Vp = 13,500 ft3
% change in reservoir pore volume @ 100 psi decline = dVp ÷ Vp =13,500 ÷ 45 x 106 = 0.03 %