Coupled reservoir flow and geomechanics has numerous important applications in the oil & gas industry, such as land subsidence, hydraulic fracturing, fault reaction and hydrocarbon recovery etc. High fidelity numerical schemes and multiphysics models must be coupled in order to simulate these processes and their interactions accurately and efficiently. Specifically, in the applications of CO2 sequestration, the effect of geomechanics on carbon storage estimation is not negligible. However, coupled flow-geomechanics simulations are very computationally expensive and most of the computational time is usually spent for geomechanics calculations. This paper investigates a three-way coupling algorithm that uses an error indicator to determine when displacement must be updated and whether fixed-stress iterative coupling technique is required. Numerical experiments with coupled nonlinear single-phase flow and linear poromechanics shows that the three-way coupling algorithm can speed up 4 times comparing to fixed-stress iterative coupling algorithm. Extensions to coupled compositional flow with poromechanics also shows a speed-up for 5 times for continuous CO2 sequestration applications and 2 times for surfactant-alternating-gas applications (SAG). The substantial speed up makes the three-way coupling algorithm of flow and geomechanics feasible in the large-scale optimizations. Based on the three-way coupling of compositional flow and geomechanics, we experimented two black box optimization algorithms, covariance-matrix adaptation evolution strategy (CMA-ES) and genetic algorithm (GA), for the optimization of well controls during SAG process to maximize CO2 storage volume. CMA-ES outperforms GA in that it is more robust, and it achieves higher objective function value in less simulation runs. The optimized SAG process achieves 27.55% more CO2 storage volume and reduces water and surfactant consumption by 54.84%.
ABSTRACT: Injection of fluids in the subsurface changes the local pore pressure and effective stresses of the target formation. Thermo-elastic and poro-elastic responses of the rock contribute to these changes of stresses. In this study, we show that these changes of effective stress are also heavily influenced by reservoir heterogeneity through numerical simulation. For such purpose, we built a reservoir model of Cranfield which hosts a typical CO2 EOR site in the USA. The model includes vertical heterogeneity in both petrophysical and geomechanical properties estimated from well-logging analysis and laboratory experiments. We performed coupled thermo-poro-elastic reservoir simulation using CMG-GEM simulator.
The simulation results show that CO2 injection changes horizontal stresses with competing poro-elastic and thermo-elastic effects. The near-injector region exhibits a large temperature reduction with ensuing total and effective horizontal stress reduction. Reservoir heterogeneity contributed to defining the initial state of horizontal stress and also the changes. The results show that drastic changes of temperature likely favored open-mode fractures near the injector at Cranfield. However, fracturing of the entire reservoir layer and the sealing layers (upper and lower) is unlikely because of a high horizontal stress and a low hydraulic communication with the injection zone.
Geological sequestration of carbon dioxide (CO2) can alleviate carbon emissions to the atmosphere by injecting CO2 into depleted reservoirs and aquifers. However, safe and permanent storage of CO2 in deep geological formations require a proper injection strategy based on the formation capacity and stress conditions to avoid high pore pressure buildup that may lead fault shear reactivation or open-mode fractures. Characterizing the evolution of the state of stress upon CO2 injection is a complex problem that includes thermo-elastic and poro-elastic coupled processes (Espinoza and Santamarina, 2011; Kim and Hosseini, 2013 & 2017). CO2 injection increases reservoir pore pressure and alters local stress due to fluid flow and compressibility. Further, injecting CO2 at lower temperature than the reservoir shrinks the rock resulting in effective stress reduction. These mechanisms may alter the geomechanical equilibrium and induce open-mode and shear-mode fractures in the reservoir.
The Cranfield reservoir in Mississippi implemented CO2 injection for enhanced oil recovery and carbon sequestration (Hovorka et al., 2013). A total of 0.5 million tons of CO2 were injected in the water leg solely for carbon sequestration research (Southeast Regional Carbon Sequestration Partnership - www.secarbon.org).
We call this section of the formation the Detailed Area of Study (DAS) in this paper. DAS area includes one injector (CFU31F-1) and two observation wells (CFU31F-2 and CFU31F-3) perforated at the interval of the Tuscaloosa sandstone (Hovorka et al., 2013; Lu et al., 2012). Field observations of bottom-hole pressure (BHP) during the CO2 injection in DAS suggest a possible geomechanical failure (open-mode fracture) and permeability modification near-wellbore region during injection (Delshad et al. 2013; Kim and Hosseini, 2013; Soltanian et al., 2016; Min et al., 2017). Further, the observed large bottom-hole temperature decrease at CFU31-F1 is regarded as the reason for open-mode failure and absence of pressure increase with increasing injection rate (Kim and Hosseini, 2013).
Lu, Xueying (The University of Texas at Austin) | Lotfollahi, Mohammad (The University of Texas at Austin) | Ganis, Benjamin (The University of Texas at Austin) | Min, Baehyun (Ewha Womans University) | Wheeler, Mary F. (The University of Texas at Austin)
CO2 capture and sequestration in subsurface reserves are expensive processes. Flue gas can be directly injected into the oil and gas reservoirs to eliminate the cost of CO2 separation from power plant emissions and simultaneously enhance hydrocarbon production that may offset the cost of gas compression. However, gas injection in subsurface resources is often subject to poor volumetric sweep efficiency caused by low viscosity and low density of the injection fluid and formation heterogeneity. This paper aims to study gas mobility control techniques of water alternating gas (WAG) and foam in Cranfield and characterize key operational parameters to the success of the process. A coupled compositional flow and geomechanics simulator, IPARS, is used to accurately simulate the underlying physical processes, with a field scale numerical model, over the desired time-span. We map flow patterns to identify risks of leakage due to interactions of viscous, gravitational, and capillary forces. A hysteretic relative permeability model enables modeling local capillary trapping. Foam mobility control technique is examined to investigate the eminent level of CO2 capillary trapping by an implicit texture foam model. The WAG and foam injection process are optimized for the number of cycles, length of the cycles using the genetic algorithm (GA) in the UT optimization toolbox. The coupled flow-mechanics model can detect the effect of the plausible interaction of geomechanics and fluid flow on CO2 plume extension. Field-scale simulations indicate that during WAG and foam processes, the oil recovery increased significantly and CO2 storage increased by 30% and 49% of during the injection spam compared to continuous gas flooding, respectively. Optimized foam process saved 25% water and surfactant consumption comparing to base case foam processes while achieving approximately the same oil recovery.
Marchesini, Pierpaolo (Lawrence Berkeley National Laboratory (LBNL)) | Daley, Thomas (Lawrence Berkeley National Laboratory (LBNL)) | Ajo-Franklin, Jonathan (Lawrence Berkeley National Laboratory (LBNL))
In this work, we used Continuous Active-Source Seismic Monitoring (CASSM), with cross-well geometry, to measure variation in seismic coda amplitude, as a consequence of effective stress change (in the form of changes in pore fluid pressure). To our knowledge, the presented results are the first in-situ example of such crosswell measurement at reservoir scale and in field conditions. Data compliment the findings of our previous work which investigated the relationship between pore fluid pressure and seismic velocity (velocitystress sensitivity) using the CASSM system at the same field site (Marchesini et al., 2017, in review). We find that P-wave coda amplitude decreases with decreasing pore pressure (increasing effective stress). Introduction In recent literature, many examples of time-lapse or 4D seismic surveys focused on monitoring changes in reservoir properties by way of induced variation in seismic wave propagation (Landro and Stammeijer, 2004; Vasco, 2004; Sayers, 2006; Duffaut, et al., 2011; Trani, et al., 2011).
ABSTRACT: Up to 2015, about 5 million metric tons of CO2 have been injected into the Lower Tuscaloosa sandstone at Cranfield field, Mississippi. Pressure monitoring at one injection well shows that the bottom-hole pressure did not increase with the imposed injection rates as expected. Above the injection zone, pressure gauges measured a change of pore pressure of approximately 0.1 MPa in the absence of leaks. These two unexpected responses during the injection suggest potential geomechanical events induced by CO2 injection. We conducted triaxial tests in Tuscaloosa sandstone rock samples with CO2-acidified brine in order to understand chemo-poromechanical processes that may have contributed to these unexpected responses. Experimental results include measurements of permeability, relative permeabilities, quasi-static and dynamic elastic moduli, Biot coefficient, and chemically-induced creep at in-situ reservoir stresses. Results show a marked anisotropy in transport properties originated from features up to the scale of a few millimeters. Rock samples exhibited significant plastic strains upon loading and yield stress consistent with current burial depth. Creep rate increases more than one order of magnitude after CO2 injection. Chemically-induced creep deformation seems insufficient to cause significant reservoir compaction but may have contributed to horizontal stress relaxation.
Carbon dioxide (CO2) geological storage can help reduce CO2 emissions by disposal into depleted hydrocarbon reservoirs and deep saline aquifers. However, injecting large amounts of CO2 at high injection rates may upset the geomechanical equilibrium of the host formation. CO2 has been injected for CO2 enhanced oil recovery (4.5 million metric tons of CO2) and geological storage (0.5 million metric tons of CO2 in the water leg) at Cranfield site in Mississippi (Southeast Regional Carbon Sequestration Partnership - www.secarbon.org). CO2 injection and storage in the water leg used one injection well (CFU31F-1) and two monitoring wells (CFU31F-2 and CFU31F-3) (Lu et al., 2012a; Butsch et al., 2013; Hovorka et al. 2013).
This paper presents numerical simulation results of pulse testing experiments carried out at a test site of a carbon capture and geological storage project in Mississippi, USA. The primary objective of this study is to validate the effectiveness of pulse testing as a monitoring tool for detecting potential CO2 leakage pathways with application to the test site. Detrending followed by Fourier transform is adopted to decompose sinusoidal pressure anomalies induced by a periodic injection of CO2 into frequencies used as target parameters of history matching. The secondary objective is to calibrate the geologic model of the test site by reducing the discrepancy between observed and simulated Fourier parameters and assess uncertainties associated with the compositional brine-CO2 flow. An assisted history matching tool that mounts global- and multi-objective evolutionary algorithms is developed, integrated with an in-house flow-geomechanics simulator, and employed to manage pulse testing simulations with a low computational cost in high-performance parallel computing environments. Grid cells in the test site are locally refined using enhanced-velocity that allows nonmatching grids on interfaces between subdomains. Experiments performed with one pulser well and two monitoring wells under steady-state conditions are considered baselines for subsequent experiments that convert one monitoring well into a production well as an artificial CO2 leakage pathway. The difference between the pressure anomalies obtained from the baseline and leak experiments are captured as a signal of CO2 leakage detection with reliability in the simulation results. A trade-off relationship between the matching qualities at the two monitoring wells is revealed more clearly by invoking multi-objective history matching than conventional global-objective history matching. This comparative study to investigate the significance of multi-objective optimization in subsurface characterization represents that diversity-preservation in the ensemble composed of qualified geologic models has the advantage of reducing bias for uncertainty quantification.
White, Deandra (The University of Texas at Austin) | Ganis, Benjamin (The University of Texas at Austin) | Liu, Ruijie (The University of Texas at San Antonio) | Wheeler, Mary F. (The University of Texas at Austin)
Permanent deformations in the solid matrix can be caused by many field scenarios, such as high injection rates. A pressure differential in the field can create geomechanical loading of large magnitude that may increase stress from an elastic regime to a plastic regime. Simple geomechanical models based on linear elasticity are insufficient in predicting these types of effects. To accurately predict rock formation damage and failure responses, nonlinear analyses based on geomaterial plasticity models should be included in modeling frameworks through rigorous coupling with reservoir flow simulators.
In this work we integrate an implementation of the Drucker-Prager plasticity model into the parallel compositional reservoir simulator, IPARS (Integrated Parallel Accurate Reservoir Simulator). Fluid flow is formulated on general distorted hexahedral grids using the multipoint flux mixed finite element method. The mechanics and flow systems are solved separately and coupled using a fixed-stress iterative coupling algorithm. This allows multiple flow models to be used with nonlinear mechanics without modification, and allows each type of physics to employ the best preconditioner for its linear systems. The fixed-stress iteration converges to the fully coupled solution on each time step.
With these components in place, we conduct a study on wellbore stability using different flow and geomaterial models. We demonstrate the capabilities of our integrated simulator in predicting near-wellbore plastic strain development and its effect on multiphase component concentrations. Our simulations run efficiently in parallel using MPI on high performance computing platforms up to hundreds or thousands of processors. The results of the simulations are useful in predicting wellbore failure.
Our integrated simulator has several distinctive features. The use of general hexahedral finite element grids is particularly well-suited to handle domain specific applications such as near-wellbore studies. The multipoint flux scheme is an accurate and convergent method, it is locally conservative, and its linear systems are efficiently solved with multigrid methods. The use of a fixed-stress iterative coupling scheme is novel for coupling nonlinear mechanics with compositional fluid flow. Finally, to achieve fast convergence rates for solving nonlinear solid mechanics problems, a material integrator has been consistently formulated to give quadratic convergence rates.
The capacity for the storage of carbon dioxide in saline aquifers remains enormous. Of all geological storage media, it provides the best storage capacity. In this study, the potential of the Shuaiba Formation, in the Falaha syncline, for geologic sequestration is assessed. A regional geo-model was built using seismic and well data (logs, cores) from the Falaha Syncline and nearby fields. The model was built to honor the heterogeneity and sequence stratigraphy of the Shuaiba carbonate platform using a five-order hierarchical conceptual model of the Shuaiba formation that merged sequence architecture and reservoir architecture together. This was achieved by honoring lithofacies, facies association packages and rock types in their corresponding depositional settings in the sequence framework. Dynamic simulations were then conducted on an upscaled geological model using a compositional reservoir simulator to determine its storage and flow capacity, plume migration pathways and to understand the physics of the fluid flow in the aquifer. Simulations are made to be conservative thus accounting for structural/stratigraphic, solubility (dissolution in resident brine) and residual trapping without accounting for the slower mineral trapping process. Detailed sensitivity studies were conducted during the simulations to understand the effect of well parameters, rock and fluid properties amongst others on the storage capacity in the aquifer. Simulation results indicate that significant volumes could be stored in the aquifer and could take a significant amount of time before the injected gas reaches the surrounding hydrocarbon producing fields. This study provides the first full field approach to characterize and to quantify the suitability of the identified aquifer for long term storage of carbon dioxide in the subsurface of UAE.
We introduce the Depth to Surface Resistivity (DSR) method as a tool that can be used to assist in detection and monitoring of CO2 and water floods within a reservoir. DSR injects current directly into the formation by energizing the metallic well casing itself, either at depth or at the surface of the well, and the resulting electric fields are measured by capacitive electrodes at the surface of the earth. The resulting potential differences are inverted to generate a resistivity model, which can be interpreted to give information about the location of injected fluids. We demonstrate the effectiveness of the DSR method with a synthetic example based on results from a field study in Texas for a CO2 flood.
Presentation Date: Wednesday, October 19, 2016
Start Time: 2:20:00 PM
Presentation Type: ORAL
Ampomah, W. (Petroleum Recovery Research Center) | Balch, R. S. (Petroleum Recovery Research Center) | Grigg, R. B. (Petroleum Recovery Research Center) | Will, R. (Schlumberger Carbon Services) | Dai, Z. (Los Alamos National Laboratory) | White, M. D. (Pacific Northwest National Laboratory)
The Pennsylvanian–age Morrow sandstone within the Farnsworth field unit of the Anadarko basin presents an opportunity for CO2 enhanced oil recovery (EOR) and sequestration (CCUS). At Farnsworth, Chaparral Energy's EOR project injects anthropogenic CO2 from nearby fertilizer and ethanol plants into the Morrow Formation. Field development initiated in 1955 and CO 2injection started December 2010. The Southwest Regional Partnership on Carbon Sequestration (SWP) is using this project to monitor CO2 injection and movement in the field to determine CO2 storage potential in CO2-EOR projects.
This paper presents a field scale compositional reservoir flow modeling study in the Farnsworth Unit. The performance history of the CO2 flood and production strategies have been investigated for optimizing oil and CO2 storage. A high resolution geocellular model constructed based on the field geophysical, geological and engineering data acquired from the unit. An initial history match of primary and secondary recovery was conducted to set a basis for CO2 flood study. The performance of the current CO 2miscible flood patterns were subsequently calibrated to the history data. Several prediction models were constructed including water alternating gas (WAG), and infill drilling using the current active and newly proposed flood patterns.
A consistent WAG showed a highly probable way of ensuring maximum oil production and storage of CO2 within the Morrow formation.
The production response to the CO2 flooding is very impressive with a high percentage of oil production attributed to CO2 injection. Oil production increasingly exceeded the original project performance anticipated. More importantly, a large volume of injected CO2 has been sequestered within the Morrow Formation.
The reservoir modeling study provides valuable insights for optimizing oil production and CO2 storage within the Farnsworth Unit. The results will serve as a benchmark for future CO2–EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world.