Hydraulic fracturing treatment is one of the most efficient conventional matrix stimulation techniques currently utilized in the petroleum industry. However, due to the spatiotemporal complex nature of fracture propagation in a naturally- and often times systematically fractured media, the influence of natural fractures (NF) and in situ stresses on hydraulic fracture (HF) initiation and propagation within a reservoir during the hydrofracturing process remains an important issue. Over the past 50 years of advances in the understanding of HF–NF interactions, no comprehensive revision of the state of the knowledge exists. Here, we reviewed over 140 scientific articles on investigations of HF–NF interactions, published over the past 50 years. We highlight the most commonly observed HF–NF interactions and their implications for unconventional oil and gas production. Using observational and quantitative analyses, we find that numerical modeling and simulation is the most prominent method of approach, whereas there are less publications on the experimental approach, and analytical method is the least utilized approach. Further, we suggest how HF–NF interactions can be monitored in real time on the field during a pre-frac test. Lastly, based on the results of our literature review, we recommend promising areas of investigation that may provide more profound insights into HF–NF interactions in such a way that can be directly applied to the optimization of fracture-stimulation field operations.

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Interaction between hydraulic fractures and natural fractures: current status and prospective directions

Abstract To identify the factors controlling high-quality deep shale gas reservoirs and the exploration and development potential of the Lower Paleozoic marine shale in the Sichuan Basin, the sedimentary environment of deep shale was comprehensively analysed using core thin sections, scanning electron microscopy, gamma ray spectrometry logging, and elemental logging data. In addition, the geological conditions of deep shale gas accumulation and the effect of tectonic processes on the preservation conditions are discussed based on the experimental data of mineral composition analysis, geochemical features, and reservoir spatial characteristics. (1) The sedimentary environment changes from an anoxic water environment to an oxygen-rich oxidizing environment from bottom to top in the Wufeng-Longmaxi Formation in southern Sichuan. The deep shale gas reservoir shows overpressure and rich gas characteristics, namely, high formation pressure (2.0~2.2), high porosity (20%~55%), and high gas content (4.0~5.0 m3/t). (2) The favourable sedimentary environment has a higher hydrocarbon generation potential and deposits of rich organic matter and siliceous particles. During the hydrocarbon generation process, the rich organic matter generates a large number of organic pores and a large specific surface area, which provides the main reservoir and adsorption space for free and adsorbed shale gas. A large number of biogenic siliceous particles provide a solid rock support framework for the shale reservoir, thereby maintaining excellent reservoir physical properties. (3) Late and small stratigraphic uplifts result in a short shale gas escape time and favourable preservation conditions. Additionally, the small-scale faults and a high-angle intersection between the fracture strike and the geostress direction are conducive to the preservation of shale gas. (4) A high formation pressure coefficient, a sedimentary environment rich in organic siliceous deep-water continental shelf microfacies, and a relatively stable tectonic structure are conducive to the accumulation of deep shale gas. 

Geological Characteristics and Controlling Factors of Deep Shale Gas Enrichment of the Wufeng-Longmaxi Formation in the Southern Sichuan Basin, China

https://www.econstor.eu/bitstream/10419/244073/1/1698872879.pdf

Hydraulic fracturing design considerations, water management challenges and insights for Middle Eastern shale gas reservoirs

Abstract The southern margin of the Sichuan Basin is characterized by strong structural deformation, complex fault structure styles and scales, and multistaged geological evolution stages, which together have created various shale gas preservation conditions. Taking Jianwu (JW)–Luochang (LC)–Shuanglong (SL) synclines as an example, the fault development characteristics and structural styles of the Longmaxi Formation were studied based on fine seismic interpretation and microscopic tests (rock acoustic emission experiments and fracture-filling inclusion tests), and the effects of the fault stage, fault class and scale, and fracture development degree on shale gas preservation conditions were analysed. Basement-involved faults, detachment faults, and intraformational microfaults are mainly developed from southeast to northwest. These fault structural types have affected the JW Syncline in the southeastern part, where faults are developed from the bottom of the Cambrian to the Wufeng–Longmaxi Formation and from the Wufeng–Longmaxi Formation to the Permian (Triassic). The SL-LC region in the northwestern part is dominated by the faults from the Wufeng–Longmaxi Formation to the Permian (Triassic). This region is dominated by NE-trending main control faults, supplemented by NW-trending, approximately EW-trending, SN-trending, and other small-scale regulating faults. Fault development can be divided into three stages, corresponding to the early, middle, and late Himalayan tectonic movements. In the early stage, a few small-scale approximately EW-trending faults had little impact on shale gas preservation. In the intermediate stage, the large number of large-scale NE-trending main control faults significantly impacted shale gas preservation. The JW Syncline mainly developed three types of faults with a high-filling degree, weak upwards penetration, and small-scale relevant fractures, which together created favourable conditions for shale gas preservation. The western and northern parts are dominated by I and II faults with large structural deformation, a low-filling degree, a large-scale, and strong penetration of related fractures, which have created unfavourable conditions for shale gas preservation. During the late stage, approximately SN- and NW-trending strike-slip reverse faults developed, and strong shear and fracture zones formed near the faults, producing unfavourable conditions for shale gas preservation. This research has clarified the characterization method of fault characteristics and stages and has established the influence of complex faults on shale gas preservation, which has an important reference value for the exploration and evaluation of shale gas reserves in complex tectonic regions. 

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Complicated Fault Characterization and Its Influence on Shale Gas Preservation in the Southern Margin of the Sichuan Basin, China

One of the challenges in reservoir management is determining the fracture density (FVDC) in reservoir rock. Given the high cost of coring operations and image logs, the ability to predict FVDC from various petrophysical input variables using a supervised learning basis calibrated to the standard well is extremely useful. In this study, a novel machine learning approach is developed to predict FVDC from 12-input variable well-log based on feature selection. To predict the FVDC, combination of two networks of multiple extreme learning machines (MELM) and multi-layer perceptron (MLP) hybrid algorithm with a combination of genetic algorithm (GA) and particle swarm optimizer (PSO) has been used. We use a novel MELM-PSO/GA combination that has never been used before, and the best comparison result between MELM-PSO-related models with performance test data is RMSE = 0.0047 1/m; R2 = 0.9931. According to the performance accuracy analysis, the models are MLP-PSO < MLP-GA < MELM-GA < MELM-PSO. This method can be used in other fields, but it must be recalibrated with at least one well. Furthermore, the developed method provides insights for the use of machine learning to reduce errors and avoid data overfitting in order to create the best possible prediction performance for FVDC prediction.

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Novel hybrid machine learning optimizer algorithms to prediction of fracture density by petrophysical data

Integrated management of water resources: A novel approach for water‐stressed regions

Use of nanoparticles as a method for enhancing oil recoveries has become an attractive prospect. Experimental evidence has shown that this technique possesses the ability to improve recoveries via wettability alteration and interfacial tension reduction amongst other strategies. In this study, we analyze the potential of nanoparticles employed in coreflood experiments. Low concentration acid was added to aid in the dispersion of the nanoparticles in the brine by protecting them from being aggregated, while enhancing the stimulation of the tight porous media. Electrokinetics was also implemented following a sequential as well as a simultaneous approach to further stimulate the fluids injected, controlling their mobility, and therefore, increasing the depth of penetration within the porous media. Several coreflood experiments were carried out on highly heterogeneous carbonate samples of Middle Eastern origin with permeabilities of around 0.1 mD. Zeta potential measurements were conducted on the inlet side of the preserved core-plugs after the conclusion of each coreflood. The findings indicated a close connection between the rate of wettability alteration observed over the duration of nano-acid fluid injection and mode of electrokinetic application. The best performing nano-acid fluids correlated with the highest shift in the magnitude of the zeta potential across all tested strategies. Results show that oil recovered via this hybrid technique was mostly 10–15% higher than that derived when only smart brine was employed.

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Insights into Nanoparticles, Electrokinetics and Hybrid Techniques on Improving Oil Recovered in Carbonate Reservoirs

Hydraulic fracturing is a stimulation process, most frequently used in tight and unconventional reservoirs for successful and economical hydrocarbon production. This study deals with the propagation behavior of induced hydraulic fractures (HFs) in naturally fractured formations within heterogeneous Middle Eastern tight gas reservoirs. Local sensitivity analysis was conducted for a Middle East candidate reservoir by varying fracture design parameters to investigate the fracture propagation behavior. After a comprehensive evaluation, a discrete fracture network-based simulator was used to introduce multiple sets of natural fractures (NFs) into the model to further analyze their interactions. Furthermore, simplistic wellbore placement analysis was also conducted. It is observed that production in tight reservoirs is governed by the presence of NFs and their distribution. This investigation analyzes HF propagation behavior and its correlated effects in the presence of NFs. Further assessment in terms of varying fracture geometry, NF sets, wellbore placement, and their effects on the conductivity are also presented. The introduced NF sets further illustrate the significance of the NF properties in this assessment. Additionally, variations in well placement demonstrate how effective the treatment can be in the presence of complex NF sets when properly located. The study is unique as it is one of its kind based on field data within the Middle East region and offers an insight into the potential concerns that may assist future fracturing operations within the region. The outcomes from this research validate the significance of NF orientation and its subsequent effects on the final HF geometry and network. Additionally, it further highlights the criticality of well placement and design strategies during hydraulic fracturing treatment design. Results describe how a minor modification with respect to the well placement can significantly affect hydraulic fracturing operations and subsequently the productivity and feasibility.

https://pubs.acs.org/doi/pdf/10.1021/acsomega.0c05380

Hydraulic Fracture Propagation and Analysis in Heterogeneous Middle Eastern Tight Gas Reservoirs: Influence of Natural Fractures and Well Placement.


 This investigation presents laboratory and field deployment results that demonstrate the potential candidacy utilizing Nano and bio-technologies to create superior chemicals for novel applications to increase oil recovery from both onshore and offshore reservoirs. Nano-technology is gaining momentum as a tool to improve performance in multiple industries, and has shown significant potential to enhance hydrocarbon production. The laboratory analysis and specifically designed coreflood results indicate there are beneficial interactions at liquid-nano solid interface that increase oil mobility. This will increase the surface activity of chemical surfactants and thereby make them the dominant agents to mobilize and recover oil from oil-bearing reservoirs. Advances in biotechnology offer another rich resource of knowledge for surface active materials that are renewable and more environmental-friendly. In addition, our studies also demonstrate that bio-surfactants are well-suited to provide superior performances in enhancing oil recovery.
 Nano-particles and biosurfactants may be included with synthetic surfactants to create novel and more efficient surface active agents for enhanced oil recovery. These formulations can promote better flow back of the injected stimulation fluids and additional mobilization to extract more oil from the matrix and micro-fractures. Laboratory experiments demonstrate that the specialized surfactant formulations created, interact with mixed or oil-wet low permeability formations to produce additional oil. Furthermore, this investigation also compares the total production on a candidate field with respect to typical water flood and the novel formulated surfactant approach. For each surfactant treatment, the overall designed injected fluid volume is 1500 m3 (~ 396,000 gallons) with 4 gpt (gallon per thousand unit) of surfactant concentration. Results indicate improved oil production with longer exposure time of the key surfactants within the reservoir. Enhanced surface wetting and super-low interfacial tension (IFT) at lower chemical concentrations are recognized to be the main mechanisms. The novel surfactant also shows stronger sustainability and endurance in keeping rock surface wettability over traditional surfactant system up to 5 times for an 8 PV wash. Furthermore, this can assist to identify and initiate the optimization of the identified mechanisms for potential applications within other compatible reservoirs.
 A number of successful field applications of EOR with special formulated nano and bio-based surfactant formulation are discussed in this paper. This unique study bridges the gap between the field realized results and lab optimization to enhance feasibility as a function of time and cost.

Abhijith Suboyin

Papers

Hydraulic fracturing design considerations, water management challenges and insights for Middle Eastern shale gas reservoirs

Integrated management of water resources: A novel approach for water‐stressed regions

Insights into Nanoparticles, Electrokinetics and Hybrid Techniques on Improving Oil Recovered in Carbonate Reservoirs

Hydraulic Fracture Propagation and Analysis in Heterogeneous Middle Eastern Tight Gas Reservoirs: Influence of Natural Fractures and Well Placement.

Novel Nano and Bio-Based Surfactant Formulation for Hybrid Enhanced Oil Recovery Technologies