Modeling transient flow behavior of eccentric horizontal well in bi-zonal formation

Water flow in a nanoscale channel is known to be affected by strong water-wall interactions; as a result, the flow considerably deviates from the conventional continuum flow. Nanochannel with a sudden contraction or expansion is the most fundamental morphological nanostructure in many nanoporous systems such as shale matrix, mudrock, membrane, etc. However, the nanoconfinement effects of water flow in nanoporous systems and its effect on macroscopic flow behavior are still evolving research topics. In this work, our recently developed pore-scale lattice Boltzmann method (LBM) considering the nanoscale effects is extended to directly simulate water flow in nanoporous systems. The results show that the flow rate is dramatically decreased in hydrophobic nanopores because of additional flow resistances at the contraction and expansion junctions. This indicates that the bundle of capillary models or the permeability averaging method overestimates the water flow rate in nanoporous media if the contraction/expansion effects between different nanopores are ignored. This work highlights the importance of wettability of the nanochannel in the determination of dynamic water flow behaviors in the contraction/expansion nanosystem. Other important aspects, including velocity distribution, flow patterns, and vortex characteristics as well as pressure variation along the flow direction, are for the first time revealed and quantified. Large differences can be found comparing gas or larger-scale water flows through the same system. A new type of pressure variation curve along the axis of flow direction is found in the hydrophobic nanochannel with a sudden contraction/expansion. This work provides the fundamental understanding of water transport through the nanoscale system with contraction and expansion effects, giving implications to a wide range of industry applications.

Simulation of Water Flow in a Nanochannel with a Sudden Contraction or Expansion.

The pressure transient behavior of water injection well has been extensively investigated under single-phase flow conditions. However, when water is injected into formation, there are saturation gradients within the water flooded area. Additionally, water imbibition is essentially important for oil displacement in dual-porosity and dual-permeability (DPDP) reservoirs. In this work, a novel semianalytical two-phase flow DPDP well test model considering both saturation gradient and water imbibition has been developed. The model was solved by the Laplace transform finite difference method. Type curves were generated, and flow regimes were identified by the model. The model features and effect of parameters were analyzed. Results show that water imbibition reduces the advancing speed of water drive front in the fracture system and slows down the water cut raising rate and the expansion speed of the two-phase zone in the fracture system. Therefore, the fluid exchange between the fracture and matrix systems becomes more sufficient and more oil will be recovered from the DPDP reservoir. The shape of pressure curves is similar for the single-phase and two-phase flow DPDP model, but the position of the proposed model is above the curves of the single-phase model. Shape factor mainly influences the interporosity period of the pressure derivatives. Water imbibition has a major effect on the whole system radial flow period of the curves. The findings of this study can help for better understanding of the oil/water two-phase flow pressure transient behavior in DPDP reservoirs considering saturation gradients and water imbibition.

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A Semianalytical Two-Phase Imbibition Model in Dual-Porosity and Dual-Permeability Reservoirs

The invention discloses a method for calculating the total skin coefficient of a multilayer oil reservoir. The method is characterized in that the relationship between the total skin coefficient and the layered skin coefficient is obtained by adopting an analytic method according to the seepage mechanics theory; the total skin coefficient is a physical property correction layered skin coefficientand formation coefficient weighted harmonic mean when the multilayer oil reservoir is jointly mined, namely, aj is a formation coefficient weighting coefficient and bj is a physical property correction coefficient. According to the method for calculating the total skin coefficient, the relationship between the total skin coefficient of the multilayer oil reservoir and the layered skin coefficientis obtained; the total skin coefficient of the multilayer oil reservoir is obtained under the conditions that each sublayer is tested and the overall test is not carried out, and thus support is supplied to joint-mining yield calculation; when one layer is not tested and other layers and the total system are tested, the skin coefficient of the untested layer can be obtained, and the reservoir protection effect of the untested layer can be evaluated; and the test cost and time are saved.

Method for calculating total skin coefficient of multilayer oil reservoir

QPG-dominated transient flow behavior of a well in a subsurface formation

The invention discloses a method for determining physical properties and crack characteristic parameters of oil and gas reservoirs with layered fracturing and commingling production. The method comprises the following steps of selecting a well with layered fracturing and commingling production as a target well, collecting and sorting basic information of the well and carrying out a shut-in pressure recovery test on the well; according to a weight coefficient determined by the product of the effective thickness of each small layer and the adding amount of sand, carrying out small-layer splitting on the commingling production output of the well; selecting common business well test software, reading pressure recovery test data and drawing a double logarithmic curve of actually measured pressure and pressure derivatives; selecting a fractured well test interpretation model to carry out well test fitting interpretation on each small layer and obtaining the characteristic parameters of eachsmall layer. The method can accurately obtain the physical properties of the small layer reservoirs and the artificial crack characteristic parameters of the well with layered fracturing and commingling production and can provide a data support for efficient development and the like of the oil and gas reservoirs.

Method for determining physical properties and crack characteristic parameters of oil and gas reservoirs with layered fracturing and commingling production

Chuan-Lei Fan

Papers

QPG-dominated transient flow behavior of a well in a subsurface formation

Method for determining physical properties and crack characteristic parameters of oil and gas reservoirs with layered fracturing and commingling production