•The CO2 huff-n-puff for EOR in the Bakken is investigated.•CO2 molecular diffusivity is a significant factor.•Sensitivity studies are performed to quantify the key parameters.•More heterogeneity is ...much favorable for the CO2 huff-n-puff process.
The combination of horizontal drilling and multi-stage hydraulic fracturing have boosted the oil production from Bakken tight oil reservoirs. However, the primary oil recovery factor is very low due to the extremely tight formation, resulting in substantial volumes of oil still remaining in place. Hence, it is important to investigate the potential of applying enhanced oil recovery methods to increase oil recovery in the Bakken formation. Although carbon dioxide (CO2) is widely used in conventional reservoirs to improve oil recovery, it is a new subject and not well-understood in unconventional oil reservoirs such as the Bakken formation. In this paper, we use numerical reservoir simulation to model CO2 injection as a huff-n-puff process with typical reservoir and fracture properties from the Bakken formation. Effects of CO2 molecular diffusion, number of cycle, fracture half-length, permeability and reservoir heterogeneity on the well performance of CO2 huff-n-puff are examined in detail. The results show that the CO2 diffusion plays a significant role in improving oil recovery from tight oil reservoirs, which cannot be neglected in the reservoir simulation model. Additionally, the tight oil formation with lower permeability, longer fracture half-length, and more heterogeneity is more favorable for the CO2 huff-n-puff process. This work can provide a better understanding of the physical mechanisms and key parameters affecting the effectiveness of CO2 injection for enhanced oil recovery in the Bakken formation.
•Effect of uneven proppant distribution on well performance is investigated.•Reservoir model with hydraulic fractures is validated using field production data.•Sensitivity studies are performed to ...quantify the key parameters.•The range for gas production due to proppant distribution is obtained.
Uniform proppant distribution in multiple perforation clusters after hydraulic fracturing plays an important role in the commercial production of shale gas. However, it is very challenging to achieve a uniform proppant distribution during operation. In some cases, proppant distribution is uneven in different clusters within the same hydraulic fracturing stage. The effect of the uneven proppant distribution on well performance is not well understood and has been largely neglected in most reservoir simulations. Hence, it is paramount to develop a reservoir simulation approach to properly examine the relationship between proppant distribution and well performance for shale gas reservoirs. In this paper, we use numerical reservoir simulation to model the proppant distribution. The reservoir model with multiple hydraulic fractures is validated by field production data from Marcellus shale. Effects of gas desorption and stress-dependent fracture conductivity are considered in the simulation model. We perform sensitivity studies to quantify the key parameters affecting the well performance between uniform and non-uniform proppant distribution. The six variables, which are cluster spacing, initial reservoir pressure, fracture conductivity, fracture half-length, fracture height, and matrix permeability, are investigated. The fracture conductivity ratio of 1:1.5:2.5:4 for four clusters in the same fracturing stage is investigated for the uneven proppant distribution scenario. This work provides insights into a better understanding of the effect of proppant distribution on well performance.
A 3D explicitly coupled geomechanics and multiphase compositional model is developed with an embedded discrete fracture model (EDFM) and finite element method (FEM) to simulate the spatiotemporal ...stress evolution in a multilayer unconventional reservoir with complex fracture geometry. Different scenarios with and without interlayer geomechanical heterogeneity are studied to provide rules of thumb for infill drilling under the impacts of reservoir permeability, fracture penetration, differential stress, and rock stiffness. With a five-layer reservoir model setup—two parent wells located in the middle layer and the top and bottom layers being potential targets, numerical results show that (a) higher reservoir permeability aggravates the stress reorientation and reduces the magnitude of minimum horizontal stress (
S
hmin
) in both the production and potential targets; (b) fracture penetration has negligible influence on the stress evolution in the top and middle layers but speeds up the stress reversal in the bottom layer; (c) larger differential stress retards the orientation change of maximum horizontal stress (
S
Hmax
) more significantly in the bottom layer than in the top layer; (d) increasing rock stiffness of the top and bottom layers accelerates the stress reversal in these layers while an opposite response is observed in the middle layer.
Highlights
A novel 3D coupled geomechanics and multiphase compositional model is developed to investigate multilayer stress interference.
The complex fracture geometry is characterized by an embedded discrete fracture model (EDFM), and solid deformation is captured by the finite element method (FEM).
The mechanisms of stress reorientation or stress redistribution spreading towards the top and bottom potential pay zones of stacked formations are proposed.
Different scenarios with and without interlayer geomechanical heterogeneity are investigated to provide rules of thumb for the multilayer infill operations.
•PPG experiments in both fracture and sandpack were successfully performed.•PPG experiments rank the effect of PPG on improving conformance.•We have developed mathematical models for gel rheology, ...adsorption, swelling ratio.•The gel transport models were implemented in a reservoir simulator (UTGEL).•The UTGEL simulator was validated against laboratory experiments.
Excess water production is a major problem that leads to early well abandonment and unrecoverable hydrocarbon in mature oil fields. Gel treatments at the injection wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. A recent gel process uses the preformed particle gels (PPGs) to overcome distinct drawbacks inherent in in-situ gelation systems, i.e. lack of control on gelation time, uncertain gelling due to shear degradation, chromatographic fractionation or change of gel compositions, and dilution by formation water.
This paper describes the results of PPG injection in both fracture and sandpack models where experimental results were used to develop and validate mechanistic models to design and optimize the flowing gel injection for conformance control processes. Crucial gel properties, such as in-situ rheology and swelling ratio in addition to oil recoveries were investigated. Water and oil permeability reduction factors were measured and modeled as a function of gel rheological properties, rock permeability, and flow rate. The PPG transport models were successfully implemented in a reservoir simulator and validated against the laboratory experiments.
Hydrogen (H2) is an attractive energy carrier to move, store, and deliver energy in a form that can be easily used. Field proven technology for underground hydrogen storage (UHS) is essential for a ...successful hydrogen economy. Options for this are manmade caverns, salt domes/caverns, saline aquifers, and depleted oil/gas fields, where large quantities of gaseous hydrogen have been stored in caverns for many years. The key requirements intrinsic of a porous rock formation for seasonal storage of hydrogen are: adequate capacity, ability to contain H2, capability to inject/extract high volumes of H2, and a reliable caprock to prevent leakage. We have carefully evaluated a commercial non-isothermal compositional gas reservoir simulator and its suitability for hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs. We have successfully calibrated the gas equation of state model against published laboratory H2 density and viscosity data as a function of pressure and temperature. Comparisons between the H2, natural gas and CO2 storage in real field models were also performed. Our numerical models demonstrated more lateral spread of the H2 when compared to CO2 and natural gas with a need for special containment in H2 projects. It was also observed that the experience with CO2 and natural gas storage cannot be simply replicated with H2.
This study used numerical simulations of CO2 storage to identify the benefits of horizontal wells for geological carbon storage, such as enhancing CO2 trapped in porous media due to relative ...permeability and capillary hysteresis. Two injection schemes were tested: one using a vertical injector and the other employing a horizontal well. The results revealed two main findings. Firstly, the horizontal injection well effectively prevented or minimized CO2 penetration into the caprock across various sensitivity scenarios and over a thousand years of CO2 redistribution. Secondly, horizontal wells provided a safe approach to trapping CO2, increasing its entrapment as a residual phase by up to 19% within the storage site. This, in turn, reduced or prevented any unexpected events associated with CO2 leakage through the caprock. Additionally, the paper proposes a practical method for designing the optimal length of a horizontal well. This method considers a combination of two parameters: the additional CO2 that can be trapped using a horizontal well and the gravity number. In the case of the reservoir model of this study, a horizontal branch with a length of 2000 m was found to be the most effective design in enhancing CO2 entrapment and reducing CO2 buoyancy.
The Embedded Discrete Fracture Model (EDFM) has emerged as a prominent piece of technology used for embedding the hydraulic behavior of rock joints in reservoir numerical models. This paper ...critically reviews its fundamentals, the latest developments, and opportunities for further research. The literature is extensive regarding novel algorithms attempting to reach more accurate and computationally effective estimates. While hydraulic fracture models seem suitable for their purposes, their assumptions might be excessively simplistic and unrealistic when assessing naturally fractured reservoirs. The paper begins by examining fractures as physical characteristics and the key mechanisms to be considered when integrating them into numerical flow simulators. The use of the EDFM technique shows promise for simulating capillary continuity and buoyancy effects in multiphase and multicomponent cases. However, there are significant limitations that hinder its widespread field-scale adoption for reservoir performance evaluation. In this regard, the lack of public-domain realistic benchmarks to validate and compare the potential of each method reinforces the difficulties of performing broader applications of the EDFM techniques in large-scale models.
Conventional Carbon Capture and Storage (CCS) operations use the direct injection of CO2 in a gaseous phase from the surface as a carbon carrier. Due to CO2 properties under reservoir conditions with ...lower density and viscosity than in situ brine, CO2 flux is mainly gravity-dominated. CO2 moves toward the top and accumulates below the top seal, thus reinforcing the risk of possible leakage to the surface through unexpected hydraulic paths (e.g., reactivated faults, fractures, and abandoned wells) or in sites without an effective sealing caprock. Considering the risks, the potential benefits of the interplay between CO2 and an aqueous solution of formate ions (HCOO¯) were evaluated when combined to control CO2 gravity segregation in porous media. Three combined strategies were evaluated and compared with those where either pure CO2 or a formate solution was injected. The first strategy consisted of a pre-flush of formate solution followed by continuous CO2 injection, and it was not effective in controlling the vertical propagation of the CO2 plume. However, the injection of a formate solution slug in a continuous or alternated way, simultaneously with the CO2 continuous injection, was effective in slowing down the vertical migration of the CO2 plume and keeping it permanently stationary deeper than the surface depth.
Fluid displacement in porous media can usually be formulated as a Riemann problem. Finding the solution to such a problem helps shed light on the dynamics of flow and consequently optimize ...operational parameters such as injected fluid composition. We developed an algorithm to find solutions to a class of Riemann problems of multiphase flow in porous media. In general, the solution to a Riemann problem in state space is a curve connecting the left and right states of the problem. The solution curves studied here are composed of classical wave curves. For a given Riemann problem, our procedure to find the solution consists of three steps: (1) guess the initial lengths of the solution’s constitutive wave curves; (2) construct each wave curve off the last state of its antecedent wave curve; and (3) iterate over the lengths of the constitutive wave curves, using an iterative solver, until the solution curve ends at the right state of the problem. We used benchmark cases from literature to verify the accuracy of the developed algorithm. Using the developed algorithm, we found solutions to some challenging cases where otherwise numerical simulators would be needed to find the type of the involved waves (i.e., rarefaction, shock or composite waves) and the coordinates of the middle states in the state space. Saturation profiles, oil cut and oil recovery for all the studied cases were computed. This information will assist us to: gain insight about the dynamics of flow, interpret core flooding measurements, assess the accuracy of developed models for foam physical properties, and verify the results of numerical simulators.
