Production system and method for producing fluids from a well

A production system and method for producing fluids from a well are presented. The production system may include a submersible pump and a jet pump. The submersible pump may be arranged within the well. The jet pump may be arranged within the well downstream of the submersible pump. The jet pump may include a power fluid intake configured to receive a power fluid and a produced fluid intake configured to receive a produced fluid. The power fluid intake may be in fluid communication with the submersible pump. The produced fluid intake may be in fluid communication with gas within the well. In an embodiment, the produced fluid intake may be in fluid communication with separated gas within an annulus of the well. Beneficially, the system may allow, among other things, a submersible pump and a jet pump to be used in combination in high gas-liquid-ratio wells without installing a gas vent line.Board of Regents, University of Texas Syste

Production system and method for producing fluids from a well

A production system and method for producing fluids from a well are presented. The production system may include a submersible pump and a jet pump. The submersible pump may be arranged within the well. The jet pump may be arranged within the well downstream of the submersible pump. The jet pump may include a power fluid intake configured to receive a power fluid and a produced fluid intake configured to receive a produced fluid. The power fluid intake may be in fluid communication with the submersible pump. The produced fluid intake may be in fluid communication with gas within the well. In an embodiment, the produced fluid intake may be in fluid communication with separated gas within an annulus of the well. Beneficially, the system may allow, among other things, a submersible pump and a jet pump to be used in combination in high gas-liquid-ratio wells without installing a gas vent line.Board of Regents, University of Texas Syste

Modeling Wettability Alteration using Chemical EOR Processes in Naturally Fractured Reservoirs

The objective of our search is to develop a mechanistic simulation tool by adapting UTCHEM to model the wettability alteration in both conventional and naturally fractured reservoirs. This will be a unique simulator that can model surfactant floods in naturally fractured reservoir with coupling of wettability effects on relative permeabilities, capillary pressure, and capillary desaturation curves. The capability of wettability alteration will help us and others to better understand and predict the oil recovery mechanisms as a function of wettability in naturally fractured reservoirs. The lack of a reliable simulator for wettability alteration means that either the concept that has already been proven to be effective in the laboratory scale may never be applied commercially to increase oil production or the process must be tested in the field by trial and error and at large expense in time and money. The objective of Task 1 is to perform a literature survey to compile published data on relative permeability, capillary pressure, dispersion, interfacial tension, and capillary desaturation curve as a function of wettability to aid in the development of petrophysical property models as a function of wettability. The new models and correlations will be tested against published data. The models will then be implemented in the compositional chemical flooding reservoir simulator, UTCHEM. The objective of Task 2 is to understand the mechanisms and develop a correlation for the degree of wettability alteration based on published data. The objective of Task 3 is to validate the models and implementation against published data and to perform 3-D field-scale simulations to evaluate the impact of uncertainties in the fracture and matrix properties on surfactant alkaline and hot water floods

Predicting adsorbed gas capacity of deep shales under high temperature and pressure: Experiments and modeling

Temperature and pressure conditions of deep shale are beyond experiment range, and the amount of adsorbed gas is difficult to determine. To predict the adsorbed gas content of deep shales under formation conditions, isothermal adsorption experiments and model building were conducted on shale samples from Longmaxi Formation in China. A temperature-dependent adsorption model based on the Langmuir equation is proposed, which can be well-fitted by observed isotherms with a high correlation coefficient. Based on the fitted parameters at 303.15 K, the isothermal adsorption curves at 333.15 K, 363.15 K, and 393.15 K are predicted, showing a good agreement with experimental curves available. Compared with previous prediction methods, the biggest advantage of the proposed method is that it can be carried out only based on one-time isothermal adsorption experiment. Based on the predictions, the downward trend of the excess adsorption curves will slow down under high temperature and pressure conditions, and when the pressure reaches a certain level (> 80 MPa), the temperature has little effect on the excess adsorption capacity. While for absolute adsorption, the gas adsorption reaches saturation much slowly at high temperature, it can also reach saturation under formation pressure. Under the burial depth of marine shale, temperature plays a major role in controlling the adsorbed gas, resulting in the decrease of adsorbed gas content in deep shale, and its ratio will further decrease as the depth increases.Cited as: Zhou, S., Wang, H., Li, B., Li, S., Sepehrnoori, K., Cai, J. Predicting adsorbed gas capacity of deep shales under high temperature and pressure: Experiments and modeling. Advances in Geo-Energy Research, 2022, 6(6): 482-491. https://doi.org/10.46690/ager.2022.06.0

A Comprehensive Numerical Model for Simulating Fluid Transport in Nanopores

Since a large amount of nanopores exist in tight oil reservoirs, fluid transport in nanopores is complex due to large capillary pressure. Recent studies only focus on the effect of nanopore confinement on single-well performance with simple planar fractures in tight oil reservoirs. Its impacts on multi-well performance with complex fracture geometries have not been reported. In this study, a numerical model was developed to investigate the effect of confined phase behavior on cumulative oil and gas production of four horizontal wells with different fracture geometries. Its pore sizes were divided into five regions based on nanopore size distribution. Then, fluid properties were evaluated under different levels of capillary pressure using Peng-Robinson equation of state. Afterwards, an efficient approach of Embedded Discrete Fracture Model (EDFM) was applied to explicitly model hydraulic and natural fractures in the reservoirs. Finally, three fracture geometries, i.e. non-planar hydraulic fractures, nonplanar hydraulic fractures with one set natural fractures, and non-planar hydraulic fractures with two sets natural fractures, are evaluated. The multi-well performance with confined phase behavior is analyzed with permeabilities of 0.01 md and 0.1 md. This work improves the analysis of capillarity effect on multi-well performance with complex fracture geometries in tight oil reservoirs.National Natural Science Foundation of China [51674010]; National Science and Technology Major Project of China [2016ZX05014]; China Scholarship Council (CSC) [201506010205]SCI(E)ARTICLE

A NEW GENERATION CHEMICAL FLOODING SIMULATOR Semi-annual Report for the Period

ABSTRACT The premise of this research is that a general-purpose reservoir simulator for several improved oil recovery processes can and should be developed so that high-resolution simulations of a variety of very large and difficult problems can be achieved using stateof-the-art algorithms and computers. Such a simulator is not currently available to the industry. The goal of this proposed research is to develop a new-generation chemical flooding simulator that is capable of efficiently and accurately simulating oil reservoirs with at least a million gridblocks in less than one day on massively parallel computers. Task 1 is the formulation and development of solution scheme, Task 2 is the implementation of the chemical module, and Task 3 is validation and application. We have made significant progress on all three tasks and we are on schedule on both technical and budget. In this report, we will detail our progress on Tasks 1 through 3 for the first six months of the second year of the project. i

A NEW GENERATION CHEMICAL FLOODING SIMULATOR Semi-annual Report for the Period

ABSTRACT 4 SUMMARY 4 Task 1: Formulation and development of Solution Scheme

Simulation Study of CO2-EOR in Tight Oil Reservoirs with Complex Fracture Geometries

The recent development of tight oil reservoirs has led to an increase in oil production in the past several years due to the progress in horizontal drilling and hydraulic fracturing. However, the expected oil recovery factor from these reservoirs is still very low. CO(2)-based enhanced oil recovery is a suitable solution to improve the recovery. One challenge of the estimation of the recovery is to properly model complex hydraulic fracture geometries which are often assumed to be planar due to the limitation of local grid refinement approach. More flexible methods like the use of unstructured grids can significantly increase the computational demand. In this study, we introduce an efficient methodology of the embedded discrete fracture model to explicitly model complex fracture geometries. We build a compositional reservoir model to investigate the effects of complex fracture geometries on performance of CO(2) Huff-n-Puff and CO(2) continuous injection. The results confirm that the appropriate modelling of the fracture geometry plays a critical role in the estimation of the incremental oil recovery. This study also provides new insights into the understanding of the impacts of CO(2) molecular diffusion, reservoir permeability, and natural fractures on the performance of CO(2)-EOR processes in tight oil reservoirs

A Comprehensive Model for Real Gas Transport in Shale Formations with Complex Non-planar Fracture Networks

A complex fracture network is generally generated during the hydraulic fracturing treatment in shale gas reservoirs. Numerous efforts have been made to model the flow behavior of such fracture networks. However, it is still challenging to predict the impacts of various gas transport mechanisms on well performance with arbitrary fracture geometry in a computationally efficient manner. We develop a robust and comprehensive model for real gas transport in shales with complex non-planar fracture network. Contributions of gas transport mechanisms and fracture complexity to well productivity and rate transient behavior are systematically analyzed. The major findings are: simple planar fracture can overestimate gas production than non-planar fracture due to less fracture interference. A “hump” that occurs in the transition period and formation linear flow with a slope less than 1/2 can infer the appearance of natural fractures. The sharpness of the “hump” can indicate the complexity and irregularity of the fracture networks. Gas flow mechanisms can extend the transition flow period. The gas desorption could make the “hump” more profound. The Knudsen diffusion and slippage effect play a dominant role in the later production time. Maximizing the fracture complexity through generating large connected networks is an effective way to increase shale gas production

XFEM-Based CZM for the Simulation of 3D Multiple-Cluster Hydraulic Fracturing in Quasi-Brittle Shale Formations

The cohesive zone model (CZM) honors the softening effects and plastic zone at the fracture tip in a quasibrittle rock, e.g., shale,which results in amore precise fracture geometry and pumping pressure compared to those from linear elastic fracture mechanics. Nevertheless, this model, namely the planar CZM, assumes a predefined surface on which the fractures propagate and therefore restricts the fracture propagation direction. Notably, this direction depends on the stress interactions between closely spaced fractures and can be acquired by integrating CZM as the segmental contact interaction model with a fully coupled pore pressure–displacement model based on extended finite element method (XFEM). This integrated model, called XFEM-based CZM, simulates the fracture initiation and propagation along an arbitrary, solution-dependent path. In this work, we modeled a single stage of 3D hydraulic fracturing initiating from three perforation clusters in a single-layer, quasi-brittle shale formation using planar CZM and XFEM-based CZM including slit flow and poroelasticity for fracture and matrix spaces, respectively, in Abaqus. We restricted the XFEM enrichment zones to the stimulation regions as enriching the whole domain leads to extremely high computational expenses and unrealistic fracture growths around sharp edges. Moreover, we validated our numerical technique by comparing the solution for a single fracture with KGD solution and demonstrated several precautionary measures in using XFEM in Abaqus for faster solution convergence, for instance the initial fracture length and mesh refinement. We demonstrated the significance of the injection rate and stress contrast in fracture aperture, injection pressure, and the propagation direction. Moreover, we showed the effect of the stress distribution on fracture propagation direction comparing the triple-cluster fracturing results from planar CZM with those from XFEM-based CZM. We found that the stress shadowing effect of hydraulic fractures on each other can cause these fractures to coalesce, grow parallel, or diverge depending on cluster spacing. We investigated the effect of this arbitrary propagation direction on not only the fractures’ length, aperture, and the required injection pressure, but also the fractures’ connection to the wellbore. This connection can be disrupted due to the near-wellbore fracture closure which may embed proppant grains on the fracture wall or screen out the fracture at early times. Our results verified that the near-wellbore fracture closure strongly depends on the following: (1) the implemented model, planar or XFEM-based CZM; and (2) fracture cluster spacing. Ultimately, we proposed the best fracturing scenario and cluster spacing to maintain the fractures connected to the wellbore.Bureau of Economic Geolog