Gas Storage Geomechanics

Geomechanical Isopach Model of Gas Storage Reservoir in Northeast US

Technology Summary

Natural gas and other hydrocarbons are commonly stored underground in either depleted oil and gas formations or in salt caverns to provide secure storage capacity and deliverability to market areas where production is limited, or to take advantage of seasonal price swings. One of the most cost-effective ways to increase storage capacity and deliverability is to operate at higher pressure, assuming the geomechanical behavior and stress conditions of the reservoir and overburden are well characterized. Terralog has developed geomechanical analysis techniques, risk analysis techniques, and design protocols to assess maximum safe operating pressures for gas storage facilities. This evaluation procedure has been successfully implemented for several gas storage fields in the US and Canada.

Terralog Services

Analysis of maximum pressure limits for gas storage reservoirs
Analysis of stresses induced by pressure cycling during storage
operations
Analysis of cap rock integrity above gas storage formations

Reservoir gas storage facilities currently provide about 4000 Bcf of US working gas capacity (95% of US total) and 70,000 MMcfd of US deliverability, or 80% of the US total (Oil and Gas Journal, 1995). One of the most cost-effective ways to increase deliverability and working gas capacity in both depleted gas storage reservoirs and aquifer storage reservoirs is to operate at higher pressure (increased delta-pressure).

Plot of maximum pressure vs. depth (from AGA database, 1993)

The typical practice in the U.S. and Canada has been to operate gas storage reservoirs at levels at or below original reservoir pressure because of concerns about caprock integrity, fracturing, faulting, and gas loss (see figure above). However, reservoir discovery pressures do not always represent the maximum short-term pressure capacity for the formation. In many instances the maximum pressure can be safely increased if the geomechanical behavior and stress conditions of the reservoir and overburden are well characterized.

Terralog has developed a protocol to assess maximum safe operating pressures, concentrating on geomechanical analysis techniques. This evaluation procedure has been documented in a recent GRI research project, and successfully implemented for several gas storage fields in the Northeast US, in California, and in Canada.

Step-by-Step Guide for Evaluating Maximum Pressure Limits
(Click Thumbnail for full size image.)

Maximum safe operating pressures for a reservoir depend on four primary factors:

•    The mechanical properties of the reservoir and overburden
•    The in situ stresses and fracture pressure in the reservoir
•    Stresses induced in the reservoir by gas cycling; and,
•    Stresses induced in the caprock material by gas cycling

The basic process for evaluating maximum pressure limits involves estimating the current rock strength and reservoir stress values with the best available data, calculating induced stresses due to pressure cycling, and then comparing the induced stresses to the estimated limiting strength and stress values. The first stage in such an assessment is to characterize the geomechanical properties of the reservoir and overburden based on the best available data. The second stage in assessing delta pressure potential is to analyze stresses induced by gas storage operations in the caprock and overburden with geomechanical models.

The final stages of a geomechanical assessment for delta pressure is to evaluate induced stresses and compare these values with estimated strength and in situ stresses.

Two basic geomechanical processes limit maximum operating pressures in gas storage reservoirs. These processes are: the tensile fracture pressure for the reservoir; and the stresses at which faulting or mechanical damage may be induced in the reservoir or caprock and overburden formations. Terralog Technologies applies state-of-the-art numerical models to evaluate these geomechanical processes for gas storage reservoirs.

Tensile fracturing can occur when the pore pressure within a formation is increased above the minimum in situ stress. At this point a hydraulic (or pneumatic) fracture is generated and propagated. The hydraulic fracture pressure provides an absolute limit to maximum storage reservoir operating pressure, as it is necessary to avoid fracturing through the caprock and allowing gas leakage into overlying permeable formations. Minimum stresses are best determined from hydraulic fracture tests in a formation. When this information is unavailable, then regional stress data can often be reviewed to provide estimates of stresses.

Another constraint on gas storage operations is the pressure at which faulting or substantial bedding plane slip may be induced in the reservoir or overburden. Such overburden damage can be induced by two mechanisms. In the first type of process, pore pressure changes within an existing fault plane may modify the effective normal stress sufficiently to activate the fault. In the second type of process, reservoir compaction and dilation can induce shear stresses in the overburden, resulting in rock failure or slip of weak zones along existing faults or along bedding planes.