Polymer flooding is an important means of improving oil recovery and is widely used in Daqing, Xinjiang, and Shengli oilfields, China. Different from conventional injection media such as water and gas, viscoelastic polymer solutions exhibit non-Newtonian and nonlinear flow behavior including shear thinning and shear thickening, polymer convection, diffusion, adsorption, retention, inaccessible pore volume, and reduced effective permeability. However, available well test model of polymer flooding wells generally simplifies these characteristics on pressure transient response, which may lead to inaccurate results. This work proposes a novel two-phase numerical well test model to better describe the polymer viscoelasticity and nonlinear flow behavior. Different influence factors that related to near-well blockage during polymer flooding process, including the degree of blockage (inner zone permeability), the extent of blockage (composite radius), and polymer flooding front radius are explored to investigate these impacts on bottom hole pressure responses. Results show that polymer viscoelasticity has a significant impact on the transitional flow segment of type curves, and the effects of near-well formation blockage and polymer concentration distribution on well test curves are very similar. Thus, to accurately interpret the degree of near-well blockage in injection wells, it is essential to first eliminate the influence of polymer viscoelasticity. Finally, a field case is comprehensively analyzed and discussed to illustrate the applicability of the proposed model.

Non-chemical CO₂ microbubbles as a mobility control technology in enhanced oil recovery (EOR) and carbon sequestration are becoming attractive. In this study, the EOR mechanisms of non-chemical CO₂ microbubble (MB) in low permeability reservoirs are experimentally investigated by the nuclear magnetic resonance (NMR) technology. This study reveals, for the first time, the EOR mechanisms of MB in a heterogeneous reservoir and its effect on pore structure. First, mobility reduction factors of MB with various gas–liquid ratios were determined, with MB at a gas–liquid ratio of 1 exhibiting the best performance under experimental conditions. Second, the coreflood experiments with NMR scanning were performed to reveal the EOR mechanisms of MB. It was observed that MB achieved an incremental oil recovery of 13.49% and 22.80% in the core sample with a permeability of 9.51 × 10⁻³ and 2.23 × 10⁻³ μm², respectively. Benefiting from MB's conformance control, the total oil recovery was increased from 38.34% to 54.57% of original oil in place by MB in parallel core flood experiments. Third, the NMR tests demonstrated that MB significantly reduced residual oil in core samples, especially in small pore areas, which highlights the improvement of sweep efficiency by MB. Lastly, the effect of MB on pore structure was studied. The NMR tests indicated a significant increase in pore space after 1 pore volume of MB flooding. Minerals in the core sample were dissolved, leading to an increase in permeability and porosity of the core sample by 17.01% and 0.31%, respectively. Overall, the results of this study provide valuable insights into the EOR mechanisms of MB at the pore scale and offer implications for EOR and carbon sequestration in low-permeability reservoirs.

With the global energy consumption on the rise and the gradual decline in conventional oil production, unconventional reservoirs have received considerable attention in the last decade. However, due to the unique physical properties and a large number of micro/nanopores in unconventional reservoirs, fluid flow in these reservoirs is considerably different from conventional ones. Therefore, it is highly important to conduct research on elucidating these fluid flow mechanisms. Furthermore, to avoid problems associated with the rapid production decline and low recovery efficiency in such reservoirs, an enhanced oil recovery technology that can efficiently and economically develop unconventional reservoirs is urgently required. This paper systematically summarizes the current research on flow mechanisms, including capillary imbibition, molecular-scale fluid flow and productivity prediction in unconventional reservoirs, and introduces the enhanced oil recovery and application status of hydraulic fracturing assisted oil displacement technology, along with a brief analysis of their advantages and disadvantages. This study is intended to serve a reference for the efficient development of unconventional reservoirs.

Polymer flooding in fractured wells has been extensively applied in oilfields to enhance oil recovery. In contrast to water, polymer solution exhibits non-Newtonian and nonlinear behavior such as effects of shear thinning and shear thickening, polymer convection, diffusion, adsorption retention, inaccessible pore volume and reduced effective permeability. Meanwhile, the flux density and fracture conductivity along the hydraulic fracture are generally non-uniform due to the effects of pressure distribution, formation damage, and proppant breakage. In this paper, we present an oil–water two-phase flow model that captures these complex non-Newtonian and nonlinear behavior, and non-uniform fracture characteristics in fractured polymer flooding. The hydraulic fracture is firstly divided into two parts: high-conductivity fracture near the wellbore and low-conductivity fracture in the far-wellbore section. A hybrid grid system, including perpendicular bisection (PEBI) and Cartesian grid, is applied to discrete the partial differential flow equations, and the local grid refinement method is applied in the near-wellbore region to accurately calculate the pressure distribution and shear rate of polymer solution. The combination of polymer behavior characterizations and numerical flow simulations are applied, resulting in the calculation for the distribution of water saturation, polymer concentration and reservoir pressure. Compared with the polymer flooding well with uniform fracture conductivity, this non-uniform fracture conductivity model exhibits the larger pressure difference, and the shorter bilinear flow period due to the decrease of fracture flow ability in the far-wellbore section. The field case of the fall-off test demonstrates that the proposed method characterizes fracture characteristics more accurately, and yields fracture half-lengths that better match engineering reality, enabling a quantitative segmented characterization of the near-wellbore section with high fracture conductivity and the far-wellbore section with low fracture conductivity. The novelty of this paper is the analysis of pressure performances caused by the fracture dynamics and polymer rheology, as well as an analysis method that derives formation and fracture parameters based on the pressure and its derivative curves.

Naturally fractured gas reservoirs have contributed significantly to global gas reserves and production. The classical gas-well decline analysis relies largely on Arps’ empirical decline models, or modern production decline analysis associating with pseudo-variables. The explicit original gas in place determination methodology is extended from homogeneous reservoir to naturally fractured reservoir under constant or variable bottom-hole pressure conditions in gas-well rate decline analysis. Then, the relationship between gas flow rate and average reservoir pseudo-pressure in the boundary-dominated flow period is re-derived. This formula is in the same format with the equation for homogeneous reservoir by due to the introduction of a new productivity index parameter that captures the inter-porosity flow between fracture and matrix in the natural fractured reservoir. The proposed step-by-step procedures are applied here, which enable the estimation of decline exponent and the explicit and straightforward determination of the original gas in place without any iterative calculations. Four simulated cases prove that our methodology can be successfully used in heterogeneous naturally fractured reservoirs with irregular boundary under constant or variable bottom-hole pressure conditions.