Search results

Multi-well hydrofracturing is a key technology in engineering, and the evaluation, control and optimization of the fracturing network determine the recovery rate of unconventional oil and gas production. In engineering terms, altering well spacing and perforation initiation sequences changes fracture propagation behavior. Fracture propagation can result in fracture-to-fracture and well-to-well interactions. This may be attributed to the interference between fractures caused by squeezing of the reservoir strata. Meanwhile, the stratal movement caused by the propagation of the fractures may lead to either the secondary fracturing of wells with primary fractures or perforation to begin fracturing. Besides, the stratal compression and squeeze of multi-well hydrofracturing will cause earthquakes; the fracture size is different owing to the different fracturing scenarios, and the occurrence of induced microseismic events is still unknown; microseismic events also affect fracture orientation and deflection. If the mechanism of the above mechanical behavior cannot be clarified, optimizing the fracture network and reduce the induced microseismic disaster becomes difficult.

In this study, combined finite element-discrete element models were used to simulate the multi-well hydrofracturing. Numerical cases compared the fracture network, dynamic stratal movement and microseismic events at 50, 75 and 100 m well spacings, respectively, and varying initiation sequence of multiple horizontal wells.

From the results, fracture propagation in multi-well hydrofracturing may simulate the propagation and deflection of adjacent fractures and induce fracture-to-fracture and well-to-well interactions. As the well spacing increases, the effect of fracturing-induced stratal movement and squeezing deformation decrease. In alternate fracturing, starting from a well located in the middle can effectively reduce the influence of stratal movement on fracturing, and the fracturing scenario with cross-perforation can minimize the influence of stratal movement. The stratal movement between multiple wells is positively correlated to microseismic events, which behaviors can be effectively weakened by reducing the strata movement.

The fracture network, thermal-hydro-mechanical coupling, fracturing-induced stratal movement and microseismic events were analyzed. This study analyzed the intersection and propagation behavior of fractures in multi-well hydrofracturing, which can be used to evaluate and study the mechanism of hydrofracturing fracture network propagation in multiple horizontal wells and conduct fracture optimization research to form an optimized hydrofracturing scheme by reasonably arranging the spacing between wells and initiation sequences of perforation clusters.

The purpose of this paper is to develop an equation for the synergistic corrosion of SRB and CO₂ based on the D-W model.

The bacterial types in the a and ß pipelines were studied by the most probable number method, and the corrosion morphology of L360 in pipeline water samples was studied by surface analysis. The corrosion rate of L360 was studied using the weight loss method. The gray correlation method was used to calculate the degree of correlation between the influencing factors of corrosion under the synergistic effect of CO₂ and SRB. The curve obtained from PIPESIM software and experiments data was then fitted using multiple non-linear regression method by MATLAB software.

The equation was used to predict the corrosion of the ß pipeline for verification, and it was found that seven out of ten excavation sites were within a 20% error range.

Using the gray correlation method, an equation that considers synergistic corrosion of SRB and CO₂ has been developed based on the D-W model. The equation could be used to predict the corrosion rate of shale gas gathering pipelines through SRB and CO₂ synergistic corrosion.

Hydrofracturing technology has been widely used in tight oil and gas reservoir exploitation, and the fracture network formed by fracturing is crucial to determining the resources recovery rate. Due to the complexity of fracture network induced by the random morphology and type of fluid-driven fractures, controlling and optimising its mechanisms is challenging. This paper aims to study the types of multiscale mode I/II fractures, the fluid-driven propagation of multiscale tensile and shear fractures need to be studied.

A dual bilinear cohesive zone model (CZM) based on energy evolution was introduced to detect the initiation and propagation of fluid-driven tensile and shear fractures. The model overcomes the limitations of classical linear fracture mechanics, such as the stress singularity at the fracture tip, and considers the important role of fracture surface behaviour in the shear activation. The bilinear cohesive criterion based on the energy evolution criterion can reflect the formation mechanism of complex fracture networks objectively and accurately. Considering the hydro-mechanical (HM) coupling and leak-off effects, the combined finite element-discrete element-finite volume approach was introduced and implemented successfully, and the results showed that the models considering HM coupling and leak-off effects could form a more complex fracture network. The multiscale (laboratory- and engineering-scale) Mode I/II fractures can be simulated in hydrofracturing process.

Based on the proposed method, the accuracy and applicability of the algorithm were verified by comparing the analytical solution of KGD and PKN models. The effects of different in situ stresses and flow rates on the dynamic propagation of hydraulic fractures at laboratory and engineering scales were investigated. when the ratio of in situ stress is small, the fracture propagation direction is not affected, and the fracture morphology is a cross-type fracture. When the ratio of in situ stress is relatively large, the propagation direction of the fracture is affected by the maximum in situ stress, and it is more inclined to propagate along the direction of the maximum in situ stress, forming double wing-type fractures. Hydrofracturing tensile and shear fractures were identified, and the distribution and number of each type were obtained. There are fewer hydraulic shear fractures than tensile fractures, and shear fractures appear in the initial stage of fracture propagation and then propagate and distribute around the perforation.

The proposed dual bilinear CZM is effective for simulating the types of Mode I/II fractures and seizing the fluid-driven propagation of multiscale tensile and shear fractures. Practical fracturing process involves the multi-type and multiscale fluid-driven fracture propagation. This study introduces general fluid-driven fracture propagation, which can be extended to the fracture propagation analysis of potential fluid fracturing, such as other liquids or supercritical gases.

Accurately evaluating fluid flow behaviors and determining permeability for deforming porous media is time-consuming and remains challenging. This paper aims to propose a novel machine-learning method for the rapid estimation of permeability of porous media at different deformation stages constrained by hydro-mechanical coupling analysis.

A convolutional neural network (CNN) is proposed in this paper, which is guided by the results of finite element coupling analysis of equilibrium equation for mechanical deformation and Boltzmann equation for fluid dynamics during the hydro-mechanical coupling process [denoted as Finite element lattice Boltzmann model (FELBM) in this paper]. The FELBM ensures the Lattice Boltzmann analysis of coupled fluid flow with an unstructured mesh, which varies with the corresponding nodal displacement resulting from mechanical deformation. It provides reliable label data for permeability estimation at different stages using CNN.

The proposed CNN can rapidly and accurately estimate the permeability of deformable porous media, significantly reducing processing time. The application studies demonstrate high accuracy in predicting the permeability of deformable porous media for both the test and validation sets. The corresponding correlation coefficients (R²) is 0.93 for the validation set, and the R² for the test set A and test set B are 0.93 and 0.94, respectively.

This study proposes an innovative approach with the CNN to rapidly estimate permeability in porous media under dynamic deformations, guided by FELBM coupling analysis. The fast and accurate performance of CNN underscores its promising potential for future applications.

Multi-well hydrofracturing is an important technology to create new fractures and expand existing fractures to increase reservoir permeability. The propagation morphology of the fracture network is affected by the disturbance between the fractures initiation sequences and spacings between adjacent wells. However, it remains unclear how well spacing and initiation sequences lead to fracture propagation, deflection and connection.

In this study, the thermal-hydro-mechanical coupling effect in the hydrofracturing process was considered, to establish a finite element-discrete element model of multistage hydrofracturing in a horizontal well. Using typical cases, the unstable propagation of hydraulic fractures in multiple horizontal wells was investigated under varying well spacing and initiation sequences. Combined with the shear stress shadow caused by in situ stress disturbed by fracture tip propagation, the quantitative indexes of fracture propagation such as length, volume, displacement vector, deflection and unstable propagation behavior of the hydrofracturing fracture network were analyzed.

The results show that the shear stress disturbance caused by multiple hydraulic fractures is a significant factor in multi-well hydrofracturing. Reducing the spacing between multiple wells increases the stress shadow area and aggravates the mutual disturbance and deflection between the fractures. The quantitative analysis results show that a decrease of well spacing reduces the total length of hydraulic fractures but increases the total volume of the fracture; compared with sequential and simultaneous fracturing, alternate fracturing can effectively reduce stress shadow area, alleviate fracture disturbance and generate larger fracture propagation length and volume.

The numerical models and results of the unstable propagation and stress evolution of the hydraulic fracture network under thermal-hydro-mechanical coupling obtained in this study can provide useful guidance for the evaluation and design of rock mass fracture networks in deep unconventional oil and gas reservoirs.

Optimized three-dimensional (3D) fracture networks are crucial for multistage hydrofracturing. To better understand the mechanisms controlling potential disasters as well as to predict them in 3D multistage hydrofracturing, some governing factors, such as fluid injection-induced stratal movement, compression between multiple hydraulic fractures, fracturing fluid flow, fracturing-induced microseismic damaged and contact slip events, must be properly simulated via numerical models. This study aims to analyze the stratal movement and microseismic behaviours induced by multistage propagation of 3D multiple hydraulic fractures.

Adaptive finite element–discrete element method was used to overcome the limitations of conventional finite element methods in simulating 3D fracture propagation. This new approach uses a local remeshing and coarsening strategy to ensure the accuracy of solutions, reliability of fracture propagation path and computational efficiency. Engineering-scale numerical models were proposed that account for the hydro-mechanical coupling and fracturing fluid leak-off, to simulate multistage propagation of 3D multiple hydraulic fractures, by which the evolution of the displacement, porosity and fracture fields, as well as the fracturing-induced microseismic events were computed.

Stratal movement and compression between 3D multiple hydraulic fractures intensify with increasing proximity to the propagating fractures. When the perforation cluster spaces are very narrow, alternate fracturing can improve fracturing effects over those achieved via sequential or simultaneous fracturing. Furthermore, the number and magnitude of microseismic events are directly proportional to the stratal movement and compression induced by multistage propagation of fracturing fracture networks.

Microseismic events induced by multistage propagation of 3D multiple hydraulic fractures and perforation cluster spaces and fracturing scenarios that impact the deformation and compression among fractures in porous rock matrices are well predicted and analyzed.

The results showed that the use of a magnetic marker could relatively accurately reflect the fracture pattern inside the rock-like material (RLM).

This study investigated the internal structure and fracture pattern of a fractured RLM. Magnetized iron oxide powder, which was used as a magnetic marker, was mixed with water and glue to form a magnetic slurry, which was subsequently injected into a fractured RLM. After the magnetic slurry completely filled the cracks inside the RLM and became cemented, the distribution and magnitude of the magnetic field inside the RLM were determined using a three-dimensional (3D) magnetic field imaging system.

A model for determining the magnetic field strength was developed using MATLAB.

This model of 3D magnetic will further be used as a finite element tool to simulate and image cracks inside the rock.

This paper aims to discuss opportunities for pairing the carbon dioxide (CO₂) points of supply from stationary sources such as power plants, steel and cement production, coal to liquid plants and refineries, with potential oil reservoirs in China.

This study builds a linear optimization model to analyze the tradeoffs in developing CO₂-enhance oil recovery (EOR) projects in China for a range of policy options to match points of supply with the points of demand (oil fields). The model works on optimizing CO₂ application costs by meeting four principal components; CO₂ storage, CO₂ capture, transport costs and additional oil recovery.

This study reveals new opportunities and economic sources to feed CO₂-EOR applications and offers reasonable options to supply CO₂ for potential points of demand. Furthermore, power plants and coal to liquid industries had the most significant and economic contributions to potential CO₂-EOR projects in China. Total annual emission reduction is expected to be 10% (based on 10 Gton annual emissions). The emission reductions and potential CO₂ storage from the different industries as follow; 94% from power plants, 4% from biofuel and 2% from coal to liquid plants.

Carbon capture and storage (CCS) is one practice aiming to reduce the amounts of anthropogenic emissions of carbon dioxide emitted into the atmosphere and reduce the related social costs. However, given the relatively high cost associated with this practice, coupling it with EOR could offer a significant financial incentive to facilitate the development of CCS projects and meet climate change objectives.

The model used in this study can be straightforwardly adapted to any geographic location where industry and policymakers are looking to simultaneously reduce CO₂ emissions while increasing hydrocarbon recovery. The model is highly adaptable to local values in the parameters considered and to include additional local considerations such as geographic variation in capture costs, taxes and premiums to be placed on CO₂ capture in so-called “non-attainment zones” where pollution capture make could make a project politically and economically viable. Regardless of how and where this model is applied, it is apparent that CO₂ from industrial sources has substantial potential value as a coproduct that offsets its sequestration costs using existing, commercially available CO₂-EOR technology, once sources and sinks are optimally paired.

Because of the increasing global oil demand, efforts have been made to further extract oil using chemical enhanced oil recovery (CEOR) methods. However, unlike water flooding, understanding the physicochemical properties of crude oil and its sandstone reservoir makeup is the first step before embarking to CEOR projects. These properties play major roles in the area of EOR technologies and are important for the development of reliable chemical flooding agents; also, they are key parameters used to evaluate the economic and technical feasibilities of production and refining processes in the oil industries. Consequently, this paper aims to investigate various important physicochemical properties of crude oil (specific gravity; American Petroleum Institute [API]; viscosity; pour point; basic sediment and water; wax; and saturate, aromatic, resins and asphaltenes components) and sandstone reservoir makeup (porosity, permeability, bulk volume and density, grain volume and density, morphology and mineral composition and distributions) obtained from Malaysian oil field (MOF) for oil recovery prediction and design of promising chemical flooding agents.

Three reservoir sandstones from different depths (CORE 1; 5601, CORE 2; 6173 and CORE 3; 6182 ft) as well as its crude oil were obtained from the MOF, and various characterization instruments, such as high temperature gas chromatography and column chromatography for crude’s fractions identification; GC-simulated distillation for boiling point distribution; POROPERM for porosity and permeability; CT-Scan and scanning electron microscopy-energy dispersive X-ray for morphology and mineral distribution; wax instrument (wax content); pour point analyser (pour point); and visco-rheometre (viscosity), were used for the characterizations.

Experimental data gathered from this study show that the field contains low viscous (0.0018-0.014 Pa.s) sweet and light-typed crude because of low sulfur content (0.03 per cent), API gravity (43.1o), high proportion of volatile components (51.78 per cent) and insignificant traces of heavy components (0.02 per cent). Similarly, the rock permeability trend with depth was found in the order of CORE 1 < CORE 2 < CORE 3, and other parameters such as pore volume (Vp), bulk volume (Vb) and grain volume (Vg) also decrease in general. For grain density, the variation is small and insignificant, but for bulk density, CORE 2 records lower than CORE 3 by more than 1 per cent. In the mineral composition analysis, the CORE 2 contains the highest identified mineral content, with the exception of quarts where it was higher in the CORE 3. Thus, a good flow crude characteristic, permeability trend and the net mineral concentrations identified in this reservoir would not affect the economic viability of the CEOR method and predicts the validation of the MOF as a potential field that could respond to CEOR method successfully.

This paper is the first of its kind to combine the two important oil field properties to scientifically predict the evaluation of an oil field (MOF) as a step forward toward development of novel chemical flooding agents for application in EOR. Hence, information obtained from this paper would help in the development of reliable chemical flooding agents and designing of EOR methods.