Cumulative Water Production Research Articles

Sensitivity analysis and uncertainty quantification based on the analytical solution for nanoparticle-stabilized foam flow in porous media

A model describing nanoparticle-stabilized foam displacement is proposed in this study. Based on literature experimental data, we include nanoparticle dependence in a simplified version of the Stochastic Bubble Population balance model in local equilibrium. To describe the gas–water fractional flow, we utilize quadratic Corey permeabilities. Our model consists of non-strictly hyperbolic conservation laws, and we investigate the existence of a global solution as a sequence of waves. This simpler model maintains the solution structure of classical Corey’s relative permeability model and allows us to obtain algebraic expressions to analyze the solution type and construct the water saturation profiles. We perform uncertainty quantification and sensitivity analysis of the model describing the foam injection assisted by nanoparticles, considering three relevant quantities of interest: breakthrough time, cumulative water production, and pressure drop. The analytical framework developed allows us to obtain these quantities. Our results show that the effect of nanoparticles is greater than the model’s uncertainty (for all quantities), suggesting that measuring it experimentally is statistically feasible. The presence of nanoparticles also significantly reduces the uncertainty propagation due to foam stabilization. From the sensitivity study, the endpoints of water and gas relative permeability are the most significant parameters for the breakthrough time. For the maximum pressure drop, the gas endpoint relative permeability and the concentration of nanoparticles stand out. Otherwise, water production is more sensitive to a foam-related parameter most of the time. We achieve convergence even using the classical Monte Carlo method, showing how analytical solutions drastically reduce computational costs.

Analysis of different objective functions in petroleum field development optimization

Oilfield development optimization plays a vital role in maximizing the potential of hydrocarbon reservoirs. Decision-making in this complex domain can rely on various objective functions, including net present value (NPV), expected monetary value (EMV), cumulative oil production (COP), cumulative gas production (CGP), cumulative water production (CWP), project costs, and risks. However, EMV is often the main function when optimization is performed under uncertainty. The behavior and performance of different objective functions has been investigated in this paper, when EMV is the primary criterion for optimization under reservoir and economic uncertainty. One of the goals of this study is to provide insights into the advantages and limitations of employing EMV as the sole objective function in oil field development decision-making. The designed optimization problem included sequential optimization of design variables including well positions, well quantity, well type, platform capacity, and internal control valve placements. A comparative analysis is presented, contrasting the outcomes obtained from optimizing the EMV-based objective function against traditional objective functions. The study underscores the importance of incorporating multiple objective functions alongside EMV to guide decision-making in oilfield development. Potential benefits in minimizing CGP and CWP are revealed, aiding in the mitigation of environmental impact and optimization of resource utilization. A strong correlation between EMV and COP is identified, highlighting EMV’s role in improving COP and RF.

Benchmarking study of coal seam gas production from Brownfield to Greenfield wells in the Surat basin, Australia

Benchmarking coal seam gas (CSG) production from Brownfield to Greenfield is an important step for assessing the development plan for Greenfield. However, the observed Brownfield production data is impacted by many factors besides reservoir properties, e.g., well spacing, well efficiency factor (WEFAC), surface pipeline network. This paper presents a case study in the Surat Basin to discuss how to benchmark CSG production from Brownfield to Greenfield. The selected Brownfield study area includes 143 wells and the Greenfield 450 proposed wells. Various tools for static modelling, decline curve analysis, and dynamic modelling were used in this study. Results show that the peak gas rate decreases quickly and the time to peak gas rate increases quickly when the WEFAC is less than 0.65. The peak gas rate is reached when the cumulative water production is between 39% and 46% of water-in-place for the selected box model. After introducing the wells’ online time ratio or WEFAC from the daily production data and the ratio of the observed cumulative water production to the expected cumulative water production, gas production rates can be predicted based on the modified Morse potential energy equation. Artificial neural networks (ANN) can be used to estimate the peak gas rate, the time to peak gas rate and the decline rate based on the reservoir properties; while the ramp-up rate can be calculated from the time to peak gas rate.

Modeling microwave heating for enhanced shale gas recovery: Fully coupled two-phase flows with heat transfer and electromagnetism in deformable reservoirs

To investigate the mechanisms of fluid migration during shale gas extraction under microwave irradiation, we developed a coupled Electromagnetic-Thermal-Hydraulic-Mechanical (ETHM) model. This model accounts for changes in fracture permeability due to variations in temperature, gas pressure, and methane desorption. The impact of microwave power on both gas production and the alteration of reservoir geological properties under microwave stimulation was investigated. Simulation results revealed that with a microwave injection power of 4,000 W, cumulative gas production increased by 45 %, reaching 64.9 million cubic meters. Additionally, the influence of initial water saturation and the diffusion damping coefficient on both gas and water production was examined. The findings show that cumulative water production was 33 % higher when microwave heating was applied compared to scenarios without microwave stimulation. An increase in initial water saturation led to a decrease in daily gas production during the early stages of extraction. Under microwave irradiation, the methane adsorption capacity at data acquisition point MP2 decreased to 0.0075 m3/kg, representing a 69 % reduction compared to conditions without microwave stimulation. Our analysis also found that daily gas production is highly sensitive to the diffusion damping coefficient. The diffusion attenuation effect had a notably negative impact on improving the recovery rate of shale gas reservoirs. In a word, this research holds significant implications for understanding the trends in gas and water production as well as the sensitivity of geological parameters during microwave-assisted thermal recovery of shale gas.

A New Method for Numerical Simulation of Coalbed Methane Pilot Horizontal Wells—Taking the Bowen Basin C Pilot Area in Australia as an Example

Coalbed methane (CBM) pilot wells typically exhibit a short production period, necessitating evaluation of their estimated ultimate recovery (EUR) through numerical simulation. Utilizing limited geological data from the pilot areas to finish history matching and subsequent production forecasting presents substantial challenges. This paper introduces a comprehensive numerical simulation workflow for CBM pilot wells, encompassing the following steps. Initially, geological parameters are categorized into two groups based on their statistical distribution trends: trend parameters (i.e., gas content, permeability, Langmuir volume, and Langmuir pressure) and non-trend parameters (i.e., fracture porosity, gas–water relative permeability, and rock compressibility). The probability method is employed to ascertain the probable high and low limits for trend parameter distributions, while empirical or analogous methods are applied to define the boundaries for non-trend parameters. Subsequently, the parameter sensitivity analysis is conducted to understand the influence of varying parameters on cumulative gas and water production. Conclusively, experimental design algorithms generate over 100 simulation cases using the identified sensitive parameters, from which the top ten optimal cases are chosen for EUR prediction. This workflow features two technological innovations: (1) considering the most comprehensive set of reservoir parameters for uncertainty and sensitivity analyses, and (2) considering the matching accuracy of both cumulative production and dynamic production trends when selecting optimal matching cases. This approach was successfully implemented in the C pilot area of the Bowen Basin, Australia. In addition, it offers valuable insights for numerical simulation of unconventional natural gases, such as shale gas.

Geothermal resource evaluation in the Sichuan Basin and suggestions for the development and utilization of abandoned oil and gas wells

In this paper, the potential seven sets of geothermal resources in the Sichuan Basin were evaluated by using a method for rapidly calculating geothermal resources in the sedimentary basins by multi data fusion, and suggestions on geothermal development and utilization are made based on the basic characteristics of abandoned wells in the oil and gas fields. The results show that the Sichuan Basin is rich in geothermal resources. The total resources of 7 sets of thermal reservoirs reach 4.26 × 1013 GJ, of which the Qixia-Maokou Formation has the largest potential geothermal resources, reaching 1.36 × 1013 GJ. The Permian Qixia-Maokou Formation in southern Sichuan Basin has the conditions to prioritize the development of geothermal resources and has the characteristics of the highest temperature of formation water and the largest current and cumulative water production. At the same time, according to the formation temperature of abandoned oil and gas wells, they are divided into two types of wells, and different geothermal resource utilization methods are proposed. The research results can provide a model for the evaluation of geothermal resources in sedimentary basins and a resource basis for the development of geothermal resources in the Sichuan Basin.

Study on Interpretation Method of Multistage Fracture Tracer Flowback Curve in Tight Oil Reservoirs.

Multistage fracturing is widely used in the development of tight oil reservoirs, and the fine description of postfracturing fracture networks is a challenge in tight oil reservoir development. Based on the formation mechanism of dual-wing fractures and the principles of tracer flowback, a mathematical model for tracer concentration in dual-wing fractures is established by considering the convective diffusion of the tracer within the fractures. An interpretation method for tracer flowback curves, utilizing a combination of Gaussian fitting and theoretical equation inversion, is developed to provide a detailed description of fracture parameters such as fracture half-length, fracture width, and fracture conductivity in the postfracturing fracture network. This method can be rapidly applied in field practices. Application examples demonstrate that the relative errors between the calculated cumulative oil and water production using this method and the actual data are less than 5%, validating the accuracy and applicability of the established mathematical model for tracer flowback and the interpretation method for tracer concentration curves in addressing practical problems.

The effect of gas solubility on the selection of cushion gas for underground hydrogen storage in aquifers

Underground hydrogen storage (UHS) is gaining worldwide attention as an efficient solution for energy supply-demand imbalance. However, deploying UHS at full scale encounters several challenges. One of the primary challenges is selecting a suitable cushion gas to optimize hydrogen storage and withdrawal efficiency. In the existing literature cushion gas dissolution in the resident reservoir fluid is not considered as one of the technical selection criteria and we aim to show in this paper that it is critically important as it affects hydrogen recovery, pressure maintenance and hydrogen purity. With a focus on hydrogen storage in aquifers, we investigated cushion gas solubility in water. Three potential cushion gases—carbon dioxide, methane, and nitrogen—were assessed through large-scale compositional simulations using a conceptual aquifer model, considering temperature and pressure conditions corresponding to the reservoir depth. Gas solubility analysis involved examining changes in reservoir pressure, water production, injected cushion gas volume, and gas saturation changes during the cyclic process. Two distinct scenarios, with and without gas solubility, were considered to understand the effect of solubility on produced hydrogen purity and efficiency. Results indicate that increasing cushion gas solubility decreases final hydrogen recovery. For the case of carbon dioxide, due to its high solubility in the reservoir water, hydrogen purity is reduced to 30 % and hydrogen recovery factor falls by 18 % compared to using methane and nitrogen. Despite this, carbon dioxide dissolution can favorably reduce cumulative water production and mitigate severe reservoir pressure drops during production. Therefore, the dissolution phenomenon should be a key consideration in the screening of cushion gases and subsequently in the design and operation of UHS. Understanding the relationship between cushion gas solubility and hydrogen production efficiency contributes to enhancing the overall performance, and the long-term success of UHS projects.

Hybrid Framework for Enhanced Dynamic Optimization of Intelligent Completion Design in Multilateral Wells with Multiple Types of Flow Control Devices

Multilateral wells (MLWs) equipped with multiple flow control devices (FCDs) are becoming increasingly favored within the oil sector due to their ability to enhance well-to-reservoir exposure and effectively handle unwanted fluid breakthrough. However, combining various types of FCDs in multilateral wells poses a complex optimization problem with a large number of highly correlated control variables and a computationally expensive objective function. Consequently, standard optimization algorithms, including metaheuristic and gradient-based approaches, may struggle to identify an optimal solution within a limited computational resource. This paper introduces a novel hybrid optimization (HO) framework combining particle swarm optimization (PSO) and Simultaneous Perturbation Stochastic Approximation (SPSA). It is developed to efficiently optimize the completion design of MLWs with various FCDs while overcoming the individual limitations of each optimization algorithm. The proposed framework is further enhanced by employing surrogate modelling and global sensitivity analysis to identify critical parameters (i.e., highly sensitive) that greatly affect the objective function. This allows for a focused optimization effort on these key parameters, ultimately enhancing global optimization performance. The performance of the novel optimization framework is evaluated using the Olympus benchmark reservoir model. The model is developed by three intelligent dual-lateral wells, with inflow control devices (ICDs) installed within the laterals and interval control valves (ICVs) positioned at the lateral junctions. The results show that the proposed hybrid optimization framework outperforms all industry-standard optimization techniques, achieving a Net Present Value of approximately USD 1.94 billion within a limited simulation budget of 2500 simulation runs. This represents a substantial 26% NPV improvement compared to the open-hole case (USD 1.54 billion NPV). This improvement is attributed to more efficient water breakthrough management, leading to a notable 24% reduction in cumulative water production and, consequently, a 26% increase in cumulative oil production.

The mathematical model and analysis of the nanoparticle-stabilized foam displacement

This work proposes a mathematical model to study the foam displacement in porous media stabilized by nanoparticles. We consider a simplification of the Stochastic Bubble Population balance model in local equilibrium, with nanoparticle dependence inspired by the experimental data from the literature. It consists of a non-strictly hyperbolic system of conservation laws, which is solved for the generic initial and injection conditions. We investigate the existence of a global solution as a sequence of waves following the Conservation Laws Theory. When the solution is composed of two or more waves, we present necessary and sufficient conditions to guarantee the compatibility of these wave sequences. The analytical solution for the nanoparticle-stabilized foam displacement in porous media allowed us to quantify the effect of nanoparticles on foam displacement, focusing on the breakthrough time and cumulative water production. In agreement with the literature, when only gas is injected, the breakthrough time and the water production increase with the nanoparticle concentration. Although, we also observe that the effect of nanoparticles is less pronounced for high nanoparticle concentration. Counterintuitively, during gas-water co-injection for a certain parameter range, adding nanoparticles changes the mathematical solution qualitatively, yielding a negligible effect on water production. We discuss the most favorable conditions to observe the action of nanoparticles in laboratory experiments.

Numerical approach on production optimization of high water-cut well via advanced completion management using flow control valves

With the development of smart downhole control devices, such as the electric flow control valve (FCV), research on completion optimization using FCV control is gaining traction for successful field production management. Applying and verifying its applicability to actual assets with uncertain production issues occur are important. This study focuses on managing downhole devices to optimize fluid production in an actual onshore oil field in Alberta, Canada. The target field has been in production operation for over 20 years, and water flooding was used in the early stages of production to maintain reservoir pressure. However, according to the flow characteristics of the field, water injection caused a high water-cut issue due to water channeling. To mitigate the problem, proactive and reactive strategies were investigated to optimize FCV control. Additionally, the effect of completion optimization was estimated considering both the field-level economic value and the fluid production behavior at the device level. In most optimization cases, the cumulative water production could be reduced compared with the base case without valve control. Notably, the flow-balancing strategy increased the revenue of the target field by approximately 23 MM$ by maximizing oil production and suppressing water production. However, reactive and streamline-balancing strategies, which directly control and delay water production, undermined the economic value due to the decrease in oil production. The findings imply that FCV control strategy of suppressing only water production for the field with high water-cut could not be the optimal solution considering the reduction in oil production and the field’s revenue. The results of this study could be used as a reference to optimize downhole devices when applying water flooding in fields where high water-cut is expected.

Numerical Simulation of a Two-Phase Flow with Low Permeability and a Start-Up Pressure Gradient

A new numerical model for low-permeability reservoirs is developed. The model incorporates the nonlinear characteristics of oil-water two-phase flows while taking into account the initiation pressure gradient. Related numerical solutions are obtained using a finite difference method. The correctness of the method is demonstrated using a two-dimensional inhomogeneous low permeability example. Then, the differences in the cumulative oil and water production are investigated for different starting water saturations. It is shown that when the initial water saturation grows, the water content of the block continues to rise and the cumulative oil production gradually decreases.

Economic and environmental assessment of the implementation of solar chimney plant for water production in two cities in UAE

• Solar chimney power plant (SCPP) system is used to generate electrical power and produce distilled water for different wind speeds in two cities in UAE. • Sharjah and Alain cities in UAE were selected based on the geographic location and metrological data. • Alain city shows more annual electrical power and water production than Sharjah city. • The economic and environmental considerations were evaluated and compared with the reverse osmosis (RO) technique. In this paper, a solar chimney power plant (SCPP) system is modeled and simulated using MATLAB code. The economic and environmental considerations were analyzed for the SCPP. The implementation of the SCPP system in Sharjah and Al Ain cities in the United Arab Emirates (UAE) were compared in terms of electrical power generation and cumulative water production, as well as the potential of increasing the wind speed by 2.5% - 10% with a step of 2.5%. The selected cities were considered due to the big difference in the relative humidity. The results showed that even though Sharjah’s water production was more stable and consistent, Al-Ain would have significantly higher water production and slightly lower power generation. After increasing the wind speed, both cities showed similar behavior of a significant increase in water production and a slight decrease in power generation. The novel design was analyzed and compared to the reverse osmosis technology from an economic and an environmental perspective. Using the SCPP is in alignment with the 2030 vision of the UAE for both electrical power generation and water production. Furthermore, the SCPP can be an effective solution to solve the demand for energy and water and reduce the effect of greenhouse gas (GHG) emissions.

Can prechlorination improve the permeate flux and water quality of gravity-driven membrane (GDM) filtration?

Gravity-driven membrane (GDM) filtration is currently limited by the relatively low permeate flux and poor water quality. This study was aimed to investigate the effects of prechlorination (3 and 5 mgCl2/L) on the permeate flux and water quality in GDM filtration by analyzing the compositions and morphologies of the fouling layer and by evaluating virus removal and trihalomethane (THM) formation for short (7 cycles) and long (32 cycles) periods. Prechlorination showed an increased permeate flux, contributing to enhanced cumulative water production (15–68%), which was achieved by lowering the extracellular polymeric substances (EPS) content (14–31%) and the formation of a relatively thinner and looser fouling layer. Prechlorination effects lessened with longer GDM operation time owing to bacterial regrowth and formation of a thick (178–227%) and dense (57–66%) fouling layer. It also changed the dominant phylum in the eukaryotic community and limited its activities in the fouling layer. In terms of the permeate water quality, the prechlorination ensured microbial safety with a 3.2 log10 reduction of MS2 bacteriophage and negligible formation of THMs. These results demonstrate the potential of using prechlorination in GDM filtration for sustainable drinking water treatment.

Hybrid optimization approach using evolutionary neural network & genetic algorithm in a real-world waterflood development

The hybrid optimization method of using evolutionary neural network (EvoNN) and NSGA-II algorithms is applied in two case studies. The first optimization study is applied in a benchmark model of the Brugge field consisting of 20 oil producers and 10 water injectors. The two objective functions are defined as maximizing short-term net present value (NPVS) and maximizing long-term NPV (NPVL). The second study is applied to a sector model of a Middle Eastern oil field developed by waterflooding to maximize cumulative oil production and minimize cumulative water production. The real field sector model consists of four producers and three injectors and it is run for ten years with 20 time steps. Bottom-hole pressure (BHP) for producers and water injection rates (qwi) for injectors are the decision variables used in the two studies. EvoNN data-driven model is based on the predator-prey genetic algorithm used in the training and optimization of the data. The optimization results obtained by the EvoNN algorithm are then used as guiding input in the NSGA-II optimization to re-initialize the population. Overall, the Pareto optimal solution obtained by the EvoNN guided NSGA-II has a more optimal solution with better convergence and diversity compared to the NSGA-II solution. The hybrid approach of using EvoNN guided NSGA-II resulted in a 70% improvement in the convergence and the computation demand for the Brugge field model. For the real field sector model, EvoNN guided NSGA-II algorithm resulted in a better convergence obtained at all generations compared to the NSGA-II algorithm solution. The maximum total oil production determined by EvoNN guided NSGA-II is 550.6 Mm3 compared to 522 Mm3 by NSGA-II. Water oil ratio (WOR) is reduced with lower water production obtained by the EvoNN guided NSGA-II algorithm compared to the NSGA-II algorithm. The best optimal solution from the EvoNN guided NSGA-II optimization for the real field sector is determined by the net flow method (NFM) at 521.25 Mm3 oil and 5208.6 Mm3water. The Pareto optimal solutions obtained by the EvoNN guided NSGA-II algorithm provide multiple optimum solutions for the decision-maker to manage the production and injection of the wells in the waterflood development based on the requirements and operational conditions.

Experimental Performance Investigation of an Original Rotating Solar Still Design under Realistic Meteorological Conditions

This research article proposes a novel design of solar still; furthermore, it investigates, experimentally, its thermal and productivity performances, as well as its efficiency, under the realistic meteorological conditions of the city of Gafsa, Tunisia (34.4311° N, 8.7757° E), in terms of ambient temperature and solar irradiance. The novel proposed design presents a cylindrical solar still with a rotating transparent plastic (Plexiglass) cover, wiped continuously on the inner surface. A specific technological configuration of the evaporation and condensation compartments is elaborated. A real prototype is manufactured in order to carry out the performance experimental investigation. A performance comparison is carried out between the cylindrical transparent plastic cover rotating and it being fixed, for two experimentation days presenting slightly different meteorological conditions. The experimental water and plastic cover temperatures, the hourly and the cumulative water production, as well as the hourly efficiency are deeply quantified and interpreted.

Underground Gas Storage Construction in Gas Fields with Oil Ring and Edge and Bottom Water: A Case Study

ABSTRACT Most underground gas storages (UGSs) are constructed in gas fields, but there are few UGS examples constructed in a gas field with an oil ring and edge/bottom water (OR-EBW-gas field). In areas where suitable gas fields are not available for USG development, existing gas fields with oil ring and edge and bottom water have to be used to construct UGS to balance the seasonal natural gas consumption and supply. Compared with conventional gas reservoirs, fluid distribution is much more complicated in OR-EBW-gas fields and there exist different modes for storage space plan, which brings up more uncertainty for the UGS construction. In this work, an active UGS construction in an OR-EBW-gas field is studied using a comprehensive compositional numerical model. The operation parameters are firstly determined through detailed sensitivity studies. UGS construction schemes employing different porous medium spaces are then investigated to determine the optimal one. The results indicate that UGS constructed using gas cap area is the optimal scheme. After 20 I/W cycles, the predicted working load of the UGS is 1.726 × 108 m3, which reaches the designed value of 1.7 × 108 m3. The incremental cumulative water production and oil production are 0.21 × 104m3 and 0.42 × 104m3 respectively. The study shows that it is crucial to prevent the intrusion of edge water for UGS construction in an OR-EBW-gas field. The oil ring is not suitable for UGS construction due to its poor petrophysical property, but can be used as a natural barrier to separate gas cap and edge water. The formation pressure needs to be improved when the gas cap, oil ring and edge water are selected as USG construction zones. However, it will also lead to a significant increase in the formation pressure near the main control fault, which leads to a high risk of fault failure.

Three-dimensional physical simulation of water huff-n-puff in a tight oil reservoir with stimulated reservoir volume

Water huff-n-puff has been considered as a cost-effective method to enhance oil recovery in tight reservoirs. However, the physical simulation method for water huff-n-puff is still lacking up to now, so that the production behaviors of actual tight reservoirs cannot be reproduced and the EOR potentials cannot be evaluated directly by scaled models in the laboratory. In this study, mathematical models for water huff-n-puff processes in tight oil reservoirs with stimulated reservoir volume (SRV) were established, then the corresponding scaling criteria were proposed and verified. Taking the tight reservoir ZMY in the Ordos Basin as a prototype, three groups of three-dimensional physical simulations of water huff-n-puff under different conditions (PSM-1, PSM-2 and PSM-3) were designed based on the scaled parameters respectively, then performed favorably and compared comprehensively. The experimental results show that oil recovery of PSM-1 can be increased by 20.16% within 8 cycles, which shows great EOR potentials for the tight reservoir ZMY. Compared with PSM-1, oil recovery of PSM-2 reduces by 8.23%, which indicates that forced imbibition is quite a helpful and promoting mechanism, and oil recovery enhancement will be greatly limited if no imbibition effect is given play between the matrix and fractures. Comparatively, oil recovery reduces by 3.39% for PSM-3, which can be inferred that if fracture density relatively increases and all fractures are well connected, the matrix imbibition effect can be further strengthened, the high pressure can propagate faster, the elastic energy can supplement into the matrix deeper, and the effect of gravitational differentiation can be better utilized as well. It is found that cumulative oil production of the three physical simulations in the first several cycles is always relatively high, which implies that sufficient oil supply in physical models can be maintained. As oil-water interface rises, less oil and more water will be produced and different dynamic characteristics of cumulative oil and water production are shown. It is also found that all three groups of water cut curves have the same upward trend and the Sigmoidal-Logistic model can be employed to accurately depict the dynamic characteristics of water cut at different cycles. This study aims to establish a physical simulation method for water huff-n-puff in tight oil reservoirs with SRV based on the three-dimensional scaled model, which will be greatly helpful to understand the EOR mechanisms and production characteristics of water huff-n-puff. • Scaling criteria of water huff-n-puff in tight oil reservoirs with SRV were proposed and verified. • Three-dimensional physical simulation method for water huff-n-puff was established. • Oil recovery of physical simulation model can be increased by 20.16% within 8 cycles for a case study. • Forced imbibition and large-scale fracture network can greatly enhance oil recovery during water huff-n-puff. • The Sigmoidal-Logistic model can depict the dynamic characteristics of water cut at different cycles.

Numerical Simulation Research on Influencing Factors of Post-Fracturing Flowback of Shale Gas Wells in the Sichuan Basin

The horizontal well multistage hydraulic fracturing technology is the most effective way to exploit shale gas resources. Compared with conventional reservoir fracturing, the flowback rate of a fracturing fluid in a shale reservoir is extremely low, and a large amount of fracturing fluid remains in the formation. Therefore, the research on the mechanism of shale reservoir fracturing fluid flowback process will contribute to laying a theoretical foundation for improving the effect of the innovation for increasing output of shale gas wells. Based on the shale in the Sichuan Basin, this study first describes basic experiments on physical properties such as the porosity, permeability, mineral composition, wettability, and microstructure. The physical properties of shale reservoirs were also analyzed, which laid the foundation for subsequent modeling. Second, CMG software is used to establish a numerical model that fits the characteristics of the flowback process. The effect of reservoir properties, fracturing parameters, drainage–production system, chemical permeability on gas and water production in the flowback process and their mechanisms are also analyzed. According to most numerical simulation results, the lower cumulative gas production will be with the higher cumulative water production which means the higher flowback rate. The pursuit of only a high flowback rate is not advisable, and the development of the drainage–production system requires reasonable control of the fracturing fluid flowback rate. This study provides a theoretical basis for the optimization of shale gas drainage–production system after hydraulic fracturing.

Influence of different shut-in periods after fracturing on productivity of MFHW in Duvernay shale gas formation with high montmorillonite content

Drilling multi-stage fracturing horizontal wells (MFHWs) is the most effective way to unlock shale gas resources economically. This paper investigates the influence of different shut-in periods after fracturing, and their impact on the productivity of MFHWs in the Duvernay shale gas formation. This western Canadian formation has a high montmorillonite content which impacts the findings. A Duvernay shale core with high montmorillonite content was used to study gas–water relative permeability. Unsteady state tests were conducted under a variety of soaking times. The experiments demonstrated that the Permeability Jail for relative permeability curves exist in a water saturation range of 60% – 80%. This phenomenon partly explains the rapid gas production decline and a long period of little water production during the formal production in a typical shale gas well. Clay in shale mainly contains illite and montmorillonite. They have surface hydration, which occurs fast enough to cause induced fractures that improves the seepage capacity initially when the core is soaked. As the soaking time prolongs, there is an osmotic hydration expansion of the montmorillonite blocking pore throats and a corresponding reduction of the seepage capacity. The relative permeability increases during the soaking days one to four. After four soaking days, relative permeability begins to slowly decrease over time. Study calculations found that 61.4% – 75.6% of the total fracturing fluid filtrates into the formation. During days one to six of the soaking, the filtration volume increases significantly due to a high initial pressure in the fractures after pump shutdown. After seven days of soaking, the filtration velocity decreases due to the pressure drop and the difficulty of compression caused by more and more fluid in the formation. Based on reservoir simulations of 600 days, the relative permeability value in the near fracture zone and the cumulative gas production are the greatest on day four of the shut-in. The longer the shut-in period, the greater the initial water production rate and cumulative water production reaching a maximum at four shut-in days. In this Duvernay area with high montmorillonite content, the optimal shut-in period after fracturing was determined to be four days.