Geomechanical Effects of CO 2 Injection under Thermal and Fracturing Conditions

Size: px
Start display at page:

Download "Geomechanical Effects of CO 2 Injection under Thermal and Fracturing Conditions"

Transcription

1 Geomechanical Effects of CO 2 Injection under Thermal and Fracturing Conditions Somayeh Goodarzi Dr. Antonin Settari University of Calgary August 20, 2012 UK-Canada CCS Mission meeting

2 Introduction and Methodology Geomechanical Mechanisms The purpose of this research is to improve the modeling technique for fracture propagation within a coupled flow and geomechanical model in order to be applicable to design injection schemes for CO 2 sequestration projects considering the associated geomechanical mechanisms. Investigating the caprock integrity under upward fracture propagation with this model is another objective of this research. Studying the thermal aspects of CO 2 injection and the effects of injection temperature on fracture pressure, injectivity and the pace of fracture propagation will be the final contribution of this work. Fault reactivation Surface uplift Shear Failure Fracturing Thermal effects n=n+1 n=0 Reservoir model, Solve for Saturation (S) and Pressure (P) and Temperature (T) Converged? Update stress dependant permeability multiplier, k=f(σ) P, T σ Yes No Geomechanical model, solve for displacements (u) and update stresses (σ)

3 S v Boundary conditions on outside boundary H f S hy 2 wf K f = R fa PH f *4(1 υ ) ( P Pfoc ) H f *4(1 υ ) w f = = E E T r = K m A m K + K m A m f A f = 1+ R fa w 12K 3 f m w = S hx f ( P P ν and E are the poisson s Ratio and Young s Modulus of the rock P and P foc are the block and fracture opening pressure w and w f are the block and fracture thickness R fa is the reduction factor (Sneddon, 1969) K m and K f are the matrix and fracture permeability A m and A f are the matrix and fracture surface area for flow foc ) X-direction transmissibiliy Multiplier Partially coupled fracture model Net Pressure(kpa)

4 Geomechanical Modeling for CO 2 Storage in Nisku Aquifer in Wabamun Lake Area in Canada WASP Project Area S hmax Nisku Aquifer Boundary S hmin CSPG Atlas, 1994

5 Isothermal Injection Considering Formation Fracturing Gas saturation after 50 years of isothermal CO 2 injection at 2 Mton/yr allowing fracture initiation and propagation. The fracture half-length and full height for the isothermal model after 30 years of injection reaches 7.5 m and 43 m, and after 50 years of injection is approximately 27.5 m and 25 m, respectively. Top of the 42-m Calmar layer Allowing dynamic fracturing (by removing the bottomhole pressure restriction) has the potential for increasing the well injectivity. However it is important to model (and monitor in the actual operation) the fracture growth for several reasons: 1) to make sure fracture would not propagate through the caprock to the extent that it would create a loss of containment (i.e., connect to other permeable zone), (2) to use the information on fracture length to design correctly the well pattern, and (3) to be able to control the injection rates to avoid excessive fracture lengths. Since there is no stress contrast in the caprock compared to the reservoir zone in the study area (Wabamun Lake), there is no effective barrier to height growth.

6 Thermal effects on dynamic fracturing Gas saturation at well block cross section for thermal model (Left); Comparison of fracture propagation pressure for isothermal and thermal model (Right) Top of the 42-m Calmar layer Bottomhole pressure (kpa) Isothermal (ΔT=0) Thermal (ΔT=30) Time (year) The fracture half-length and height in the thermal case at 30 years are m and 112 m, respectively, which is larger compared to the isothermal case. After 50 years of injection, the half-length grows to but the fracture height remains constant. As expected, since the thermal effects cause reduction in the total stress, the fracture propagates at much lower pressure in the presence of thermal effects. The reduced injection pressure means smaller pressure gradient into the formation and therefore reduced injectivity, which must be compensated for by faster fracture growth. The injection temperature of CO 2 can be controlled at the surface and it can be therefore one of the optimization variables. Limited fracture growth into the caprock is not necessarily harmful. Only if the fracture would grow completely through the caprock, then it could serve as a fluid source for the shallower geological layers.

7 Reservoir Simulation Analysis of Carbon Dioxide Storage in a Saline Aquifer in the Ohio River Valley Pressure and stress magnitudes with depth (Left) The well location and the generalized stratigraphy intersected by the well are illustrated. The black box shows the boundaries of the area of previous work by Lucier et al. (2006). Modified from Gupta (2008) (Right)

8 Effect of Injection Rate on Dynamic Fracture Model Fracture length for dynamic fracture model with 7.2E4 m 3 /day, 8.7E4 m 3 /day and 1.44E5 m 3 /day injection rate (Left) Cumulative injection for dynamic and static fracture models and the model with no fracture (Right) Fracture length (m) Q=1.44E5 m3/day Q=8.7E4 m3/day Q=7.2E4 m3/day Time (yr) Cumulative injection (Mt) 12 No fracture 10 Dynamic fracture(7.2e4m3/day) Dynamic Fracture(8.7E4m3/day) 8 Dynamic fracture(1.44e5m3/day) Static fracture(300m half-length,37mpa BHP) Time (year) In order to maximize the cumulative injection of CO2, the injection rate can be optimized based on fracture length and height and extent of the CO2 plume. Modeling of dynamic fracture propagation with injection rates of 8.7E4 m3/day and 1.44E5 m3/day showed that the cumulative injection of CO2 was increased by a factor of ~3 and ~4 respectively compared to the model with no fracture (well operated under fracture pressure of 32 Mpa). Optimized scenario will have to consider balancing the peak fracture lengths with the injectivity increase.

9 Thermal Aspects of Geomechanics and Induced Fracturing in CO 2 Injection, Application to CCS in Ohio River Valley Fracture half length and bottomhole pressure with noflow boundary condition with 5E4 m 3 /day injection rate (Left) and with 4.5E4 m 3 /day injection rate (Right) and with 7.2E4 m 3 /day injection rate (bottom) Fracture Length (m) Isothermal (Q=5E4 m3/day, Δt=0) Thermal (Q=5E4 m3/day, Δt=15) Thermal (Q=5E4 m3/day, Δt=30) Time(yr) Fracture Length (m) Isothermal (Q=4.5E4 m3/day, Δt=0) Thermal (Q=4.5E4 m3/day, Δt=15) Thermal (Q=4.5E4 m3/day, Δt=30) Time(yr) If the injection rate is small, thermal diffusion (heat transfer) will dominate the process and fracture propagation. Therefore, due to thermal stress reduction, fracture length for thermal model will be higher than for the isothermal model. The difference between the fracture length of the thermal and isothermal model increases as the injection rate is reduced. In general, one expects that the thermal effect of injection on fracture propagation is a function of pressure diffusivity, thermal diffusivity and injection rate.

10 Thermoelasticity vs. Poroelasticity (Left) Pressure (kpa), (Middle) Temperature (C), (Right)Minimum effective stress (kpa) after 30 years of injection at reservoir s top layer with 4.5E4 m 3 /day injection rate. X Axis is linear and zoomed to the fracture length and Y-axis is logarithmic m (Left) Pressure (kpa), (Middle) Temperature (C), (Right) Minimum effective stress (kpa) after 30 years of injection at reservoir s top layer with 7.2E4 m3/day injection rate. X-Axis is linear and zoomed to the fracture length and Y-Axis is logarithmic m

11 Optimization Possibilities Goal: maximize injectivity For a given storage target, if both thermoelasticity and poroelasticity are considered If T inj < T res To constrain the maximum fracture length Increase injection temperature Decrease injection rate Optimization Higher capital and operating cost for transportation and injection Higher capital and operating cost for drilling more wells

12 Conclusions and main learnings Understanding the geomechanical constraints in deep saline reservoirs being considered as storage sites is necessary for developing the appropriate injection strategy, estimating storage potential, and quantifying injection induced seismicity. Injection above fracture pressure will have the potential to increase the well injectivity but also the possibility of fracturing the caprock. The degree of vertical propagation strongly depends on the caprock stress state and mechanical properties. Injecting CO 2 at a temperature lower than reservoir temperature reduces the fracture pressure which leads to smaller injection capacity. Therefore coupling heat transfer model with flow and geoemchanical model is necessary for accurate simulation of CO 2 storage.

13 Conclusions (continued) As the injection rate increases, thermal effects of injection on fracture propagation decreases, but tendency for fracturing increases regardless of thermal effects. At small enough injection rates, fracture propagation is controlled primarily by the injection temperature, and is accelerated as injection temperature decreases. As a result, spontaneous fracturing is expected to take place in most CCS projects in vertical wells with injection temperature below reservoir temperature, unless the injection rates are impractically low. This is an important finding which will also have consequences for caprock integrity.

14 Future plans It is now feasible to design the field injection scheme under fracturing condition and to study whether it is inevitable to inject under fracturing condition and the effects of such strategy on injectivity and caprock integrity. The dependence of fracture propagation and fracturing pressure on injection temperature opens interesting possibilities for optimization of CCS projects. The optimization process should consider as variables: injection rate and temperature, well spacing and number of wells needed and associated capital and operating costs of CO 2 heating/cooling and pipeline and injection equipment.

15 Future plans It is expected that by the end of this research, the coupled geomechanical-flow simulator will be improved such that it can more accurately simulate CO 2 injection projects and become a practical tool.