Modeling and Control of Proppant Distribution of Multistage Hydraulic Fracturing in Horizontal Shale Wells

Pore-Scale Study on Shale Oil-CO2-Water Miscibility, Competitive Adsorption, and Multiphase Flow Behaviors

Due to the fracturing fluid imbibition and primary water, oil-water two-phase fluids generally exist in shale nanoporous media. The effects of water phase on shale oil recovery and geological carbon sequestration via CO2 huff-n-puff is non-negligible. Meanwhile, oil-CO2 miscibility after CO2 huff-n-puff also has an important effect on oil-water two-phase flow behaviors. In this work, by considering the oil-CO2 competitive adsorption behaviors and the effects of oil-CO2 miscibility on water wettability, an improved multicomponent and multiphase lattice Boltzmann method is proposed to study the effects of water phase on CO2 huff-n-puff. Additionally, the effects of oil-CO2 miscibility on oil-water flow behaviors and relative permeability are also discussed. The results show that due to Jamin's effect of water droplets in oil-wetting pores and the capillary resistance of bridge-like water phase in water-wetting pores, CO2 can hardly diffuse into the oil phase, causing a large amount of remaining oil. As water saturation increases, Jamin's effect and the capillary resistance become more pronounced, and the CO2 storage mass gradually decreases. Then, based on the results from molecular dynamics simulations, the influences of oil-CO2 miscibility on oil-water relative permeability in calcite nanoporous media are studied, and as the oil mass percentage in the oil-CO2 miscible system decreases, the oil/water relative permeability decreases/increases. The improved lattice Boltzmann model can be readily extended to quantitatively calculate geological CO2 storage mass considering water saturation and calculate the accurate oil-water relative permeability based on the real 3D digital core.

Accounting for Fixed Effects in Re-Fracturing Using Dynamic Multivariate Regression

The oil and gas (O&G) industry is now as focused on minimizing costs and maximizing efficiency just as much as maximizing production. Operators are looking for new and cost-effective ways to add profitable assets to their portfolio. One such way is to re-fracture existing wells. There is evidence that these wells can be very productive in the Bakken. However, because of factors such as depletion and aging wellbore material, re-fracturing wells can be a difficult process to implement successfully and often have binding constraints on surface treating pressure (STP). This study attempts to quantify the effects that completion parameters have on re-fracturing treatment implementation by constructing dynamic fixed effects (FE) multivariate regression models. These models are not generally used in O&G and are more commonly used in economics and policy analysis. However, given that both economics and O&G deal with large amounts of uncertainty for each individual person and well, respectively, these models provide a much simpler approach to handle the uncertainty. These models also attempt to account for stress shadow effects from subsequent stages on treatment. The FE model has the advantage of treating a compilation of well treatment data as panel data and differencing out any unobservable fixed parameters. To the authors’ knowledge, this is the first study using dynamic FE models to estimate temporal stress shadow effects from one stage to the next. These models may then be thought of as estimating the boundary effects from stress shadows, which will affect treatment implementation. The novelty lies in estimating these effects, while accounting for fixed within-well variation, using simpler models than those usually found in industry. We stress that the simplicity of these models is a feature, not a bug. This study found that previous stage average STP, acid volume pumped, and perforation standoff were all statistically significant predictors of average STP with a strong temporal dependence of average STP on subsequent stages after accounting for fixed wellbore and geologic parameters. The models in this study also predict a positive marginal effect from acid volume average STP, which may seem counterintuitive, but is also backed by a previous study.

SAXS-guided unbiased coarse-grained Monte Carlo simulation for identification of self-assembly nanostructures and dimensions

Recent studies have shown that solvated amphiphiles can form nanostructured self-assemblies called dynamic binary complexes (DBCs) in the presence of ions. Since the nanostructures of DBCs are directly related to their viscoelastic properties, it is important to understand how the nanostructures change under different solution conditions. However, it is challenging to obtain a three-dimensional molecular description of these nanostructures by utilizing conventional experimental characterization techniques or thermodynamic models. To this end, we combined the structural data from small angle X-ray scattering (SAXS) experiments and thermodynamic knowledge from coarse-grained Monte Carlo (CGMC) simulations to identify the detailed three-dimensional nanostructure of DBCs. Specifically, unbiased CGMC simulations are performed with SAXS-guided initial conditions, which aids us to sample accurate nanostructures in a computationally efficient fashion. As a result, an elliptical bilayer nanostructure is obtained as the most probable nanostructure of DBCs whose dimensions are validated by scanning electron microscope (SEM) images. Then, utilizing the obtained molecular model of DBCs, we could also explain the pH tunability of the system. Overall, our results from SAXS-guided unbiased CGMC simulations highlight that using potential energy combined with SAXS data, we can distinguish otherwise degenerate nanostructures resulting from the inherent ambiguity of SAXS patterns.

The Use of Hydraulic Fracturing in Stimulation of the Oil and Gas Wells in Romania

This paper presents the application of the hydraulic fracturing method in Romania, exemplified by three case studies. In the current conditions in which the oil and gas prices have risen above the limit of affordability, Romania, one of the few producers in Europe, is trying to solve the problems that have arisen through various methods, which are as follows: offshore drilling, gas underground storage, field rehabilitation and increasing the efficiency of applied technologies. The application of hydraulic fracturing is a safe process, with minimal environmental implications and certain economic benefits. The important thing is to have the necessary energy now, in the desired quantities and with minimal expenses. The authors sought to include key issues in the application of this technology in Romania. The scientific literature on this topic has helped us to interpret the data from the field in difficult situations and were a real support in our activity. We need to provide energy support and energy security and we do not have a lot of resources. Under these conditions, the reactivation of existing deposits and the extension of the production period are essential elements. The authors designed the fracturing technologies. The data corresponding to the geological structure obtained through geological investigations, and the database corresponding to the analyzed wells from the company’s data archive were the elements used in the simulation programs. Thus, the values in the fracturing area about pore fluid permeability, layers stress, Young’s modulus of the structure and fracture toughness were established. The fluids for the fracturing operation and the proppant were chosen for each case, in accordance with the geological recommendations, by our team. Testing of the fracturing technologies for different variants of the pumping program was carried out using the Fracpro program. The variants presented in this article are some of the best solutions found. We used the step-by-step flow test to find the fracture expansion pressure and closing pressure for each case. The mini-frac program established corrections to the designed technologies during the operation quickly and with reduced costs. The designed technologies allowed us to anticipate the necessary flows and pressure, leading to the choice of equipment. The fracture operations were performed only after the projected technologies anticipated the economic benefits covering the investments for the use of the equipment and the operation itself. Knowing the measured pressure of the well and the conditions of communication with the gas/oil reservoir, a simulation of the gas/oil production that could be obtained was made with the simulator. Two situations were exemplified for a gas well and an oil well. The field production results for a two-year interval are also indicated for these wells and a comparison was made with the estimated production.

Parameter Optimization of Asynchronous Cyclic Waterflooding for Horizontal-Vertical Well Patterns in Tight Oil Reservoirs

Tight oil resources in China are mainly exploited by staged-fractured horizontal wells; horizontal wells face the problems of the rapid decline rate and low primary oil recovery. Pilot tests on the asynchronous cyclic waterflooding for the horizontal-vertical well pattern were carried out in recent years and achieved good performance. However, there are few studies on the influencing factors and parameter optimization of asynchronous cyclic waterflooding, which limits its wide application. This work took the tight oil reservoir in Yanchang formation, Fuxian area, Ordos Basin as its object, and the oil recovery mechanisms of asynchronous cyclic waterflooding for the horizontal-vertical well pattern were analyzed first. Then, the operation parameters of asynchronous cyclic waterflooding were optimized by the numerical simulation method. Among them, the injection proportion was optimized by the fuzzy synthetic evaluation method. Finally, the oilfield test was carried out based on the optimized parameters. The results showed that pressure disturbance and streamline deviation are the main oil recovery mechanisms of asynchronous cyclic waterflooding. The asynchronous mode of the diagonal well row is better than other asynchronous modes. For the injection time interval, injection-production ratio, and the injection and shut-in time, the cumulative oil production all show the trend of increasing first and then decreasing with the increase in these parameters. The optimal injection time interval and injection-production ratio are 0.5 T and 1, respectively. The optimal injection and shut-in time can be calculated by empirical formulas. Ultimately, the fuzzy synthetic evaluation model was established to optimize the injection proportion. Field practices showed that the average daily oil production of horizontal wells was increased from 1.7 to 3.0 m³ with the optimized parameters, which further verified the accuracy of the optimized parameters. This research can provide theoretical support for the effective development of tight oil reservoirs.

Electrical energy storage using compressed gas in depleted hydraulically fractured wells

Renewable forms of electricity generation like solar and wind require low-cost energy storage solutions to meet climate change deployment goals. Here, we explore the use of depleted hydraulically fractured ("fracked") oil and gas wells to store electrical energy in the form of compressed natural gas to be released to spin an expander/generator when electrical demand is high. Our reservoir model indicates that the same dual-porosity geological environment of fracked wells used to liberate hydrocarbons is also suitable for storing and releasing gas in a diurnal or seasonal cycle. Round-trip storage efficiency is calculated to be 40%-70% depending on the natural reservoir temperature. Levelized cost of storage is estimated to be $70-270/MWh, on par with pumped hydro storage. This study indicates that repurposed "fracked" wells could provide a much-needed low-cost seasonal energy storage solution at the TWh scale.

Multi-Size Proppant Pumping Schedule of Hydraulic Fracturing: Application to a MP-PIC Model of Unconventional Reservoir for Enhanced Gas Production

Slickwater hydraulic fracturing is becoming a prevalent approach to economically recovering shale hydrocarbon. It is very important to understand the proppant’s transport behavior during slickwater hydraulic fracturing treatment for effective creation of a desired propped fracture geometry. The currently available models are either oversimplified or have been performed at limited length scales to avoid high computational requirements. Another limitation is that the currently available hydraulic fracturing simulators are developed using only single-sized proppant particles. Motivated by this, in this work, a computationally efficient, three-dimensional, multiphase particle-in-cell (MP-PIC) model was employed to simulate the multi-size proppant transport in a field-scale geometry using the Eulerian–Lagrangian framework. Instead of tracking each particle, groups of particles (called parcels) are tracked, which allows one to simulate the proppant transport in field-scale geometries at an affordable computational cost. Then, we found from our sensitivity study that pumping schedules significantly affect propped fracture surface area and average fracture conductivity, thereby influencing shale gas production. Motivated by these results, we propose an optimization framework using the MP-PIC model to design the multi-size proppant pumping schedule that maximizes shale gas production from unconventional reservoirs for given fracturing resources.

A Case Study on the Optimal Design of the Horizontal Wellbore Trajectory for Hydraulic Fracturing in Nong’an Oil Shale

A horizontal well with hydraulic fractures is key to forming a fracture network in oil shale for the generated hydrocarbon flows. By considering the influence of anisotropic strength, a prediction model is proposed for fracture initiation by studying different fracture initiation modes (FIMs) in oil shale: failure of the intact rock matrix and of the bedding planes. Through a case study on Nong’an oil shale, the influences of wellbore trajectory and bedding planes on the fracture initiation pressure (FIP), location (FIL), and FIM were analyzed and the induced changes in wellbore trajectory design were concluded. The preferred angle between the wellbore axis and the minimum horizontal principal stress was the same of 90° or 270°, when the lowest required FIP corresponded to the failure of the intact rock matrix. However, when the angle corresponded to the failure of the bedding planes, the preferred direction of the wellbore axis was away from the fixed direction and not corresponding to the lowest required FIP due to the fracture morphology. The error between the theoretical and experimental results ranges from 7% to 9%. This research provides a framework for the design of horizontal wellbore trajectories in oil shale, for easier fracture initiation and more complex fracture networks.