Simulation of Injectivity and Fracture Containment: Water Injection in a Turbidite Reservoir, Offshore Ghana

SPE Europec Featured at 81st EAGE Conference and Exhibition

Clemens

Zechner

et al. 2019

Waterflooding can lead to substantial incremental oil production. Implementation of water injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as inability to estimate a value precisely) a company is willing to take. One of the key risks for water injection into a shallow reservoir is injection induced fractures extending into the caprock. If this risk is seen as "Intolerable" in an As Low As Reasonable Practicable (ALARP) analysis a decision may be made to not proceed with the project., In this study we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes and fracture propagation in the sand and bounding shale. The risk of fracture growth into the caprock was assessed by conducting Monte-Carlo simulations considering a set of modelling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters where the risk of fracture height growth was acceptable. Our simulations also allowed us to identify important factors that impact caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk of the caprock integrity is reduced. This requires introducing a limit for the Bottom Hole Pressure (BHP) including a safety margin. The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parametrisation of the model, sampling from the distribution of parameters and distance-based Generalized Sensitivity Analysis (dGSA) as well as probabilistic representation of the results. The dGSA can be used to determine which parameter has a strong impact on the BHP and hence the project and should be measured if warranted by a Value of Information analysis. The final development option to be chosen depends on a traditional NPV analysis.

Risk Assessment and Simulation of Injectivity Decline Under Uncertainty

SPE Europec Featured at 81st EAGE Conference and Exhibition

Clemens

Zechner

et al. 2019

Risk Assessment and Simulation of Injectivity Decline Under Uncertainty

SPE Production &Amp; Operations

Clemens

Zechner

et al. 2019

Summary Waterflooding can lead to substantial incremental oil production. Implementation of water-injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as the inability to estimate a value precisely) a company is willing to take. One of the key risks for water injection into a shallow reservoir is injection-induced fractures extending into the caprock. If this risk is seen as “intolerable” in an as-low-as-reasonably-practicable (ALARP) analysis, a decision might be made not to proceed with the project. In this study, we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes, and fracture propagation in the sandstone and bounding shale. The risk of fracture growth into the caprock was assessed by conducting Latin hypercube sampling considering a set of modeling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters in which the risk of fracture-height growth was acceptable. Our simulations also allowed us to identify important factors that affect caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk to the caprock integrity is reduced. This requires introducing a limit for the bottomhole pressure (BHP), including a safety margin. The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parameterization of the model, sampling from the distribution of parameters- and distance-based generalized sensitivity analysis (dGSA) as well as probabilistic representation of the results. The results indicate that the time to reach the BHP limit varies substantially, dependent on the chosen development scenario. Injection of water (1000 m3/d), with total suspended-solids content ranging from 0.1 to 0.5 ppm by volume (ppmv) and particle size from 1 to 5 µm, into long horizontal wells (2000 m) results in injection times of more than 10,000 days even for the P10 percentile. However, injection of poor-quality water (injection rate 600 m3/d, well length 600 m), with total suspended-solids content ranging from 0.5 to 5 ppmv and particle size from 10 to 30 µm, leads to the BHP limit of 10 (P10) to 740 (P90) days. The dGSA can be used to determine which parameter has a stronger impact on the BHP and, hence, on the project, and should be measured if warranted by a value-of-information analysis. In the case reported here, dGSA showed that the filter-cake permeability has a big impact on the results and, hence, will be determined by laboratory measurements. The final development option to be chosen depends on a traditional net-present-value analysis.

Viscoelastic Polymer Injectivity: A Novel Semi-Analytical Simulation Approach and Impact of Induced Fractures and Horizontal Wells

Hwang

Sharma

SPE Annual Technical Conference and Exhibition

et al. 2019

Several field cases reported that polymer injection in a horizontal well is a viable solution to increase oil recovery. The injectivity, however, may vary significantly depending on fluid, reservoir, and geomechanical conditions. Polymer injection without understanding these factors may lead to injectivity impairment, unswept zones, and fractures undesirable for the sweep. In this paper, we present a comprehensive viscoelastic polymer injectivity model for vertical and horizontal wells. We developed a simulator to compute viscoelastic polymer injectivity by accounting for particle filtration, thermo-poro-elastic stress changes, fracture propagation, flow distributions among multiple layers, and viscoelastic polymer rheology. Simulation results clearly show that the contribution of shear-thickening characteristics on the polymer can have a large impact in un-fractured wells but have a much smaller impact in fractured injectors. The impact of geomechanical stress changes and subsequent induced fractures are also highlighted. The model was then applied for a field case study to identify critical aspects needed to maintain high injectivity. Two field case wells are presented where water and viscoelastic polymer are injected for a vertical well and a horizontal well accessing the multi-layered reservoir respectively. For the two injectors, water was injected initially, and then HPAM polymer solution followed to improve oil recovery. Fracture growth and injection into a long horizontal lateral are the key factors that allowed the operator to maintain injectivity by reducing the Darcy velocity, shear rate, and shear-thickening zone. For a horizontal well, operating conditions are also identified by simulations to ensure matrix injection, which is the desired conformance and sweep improvement option.