Unconventional Reservoirs Research Articles

Dynamic prediction of fracture propagation in horizontal well hydraulic fracturing: A data-driven approach for geo-energy exploitation

Accurate and efficient prediction of hydraulic fracturing fracture propagation is of utmost importance for unconventional reservoir development. Traditional numerical simulation methods require specialized domain knowledge and technical expertise, and machine learning approach can be an alternative predictive tool for fracture propagation. Additionally, existing neural networks cannot be directly applied to hydraulic fracturing scenarios influenced by multiple coupled factors. Thus, this study presents an innovative approach, “AE-ATT-ConvLSTM”, that integrates an additional Convolutional Layer, Autoencoder, and an Attention Mechanism Feature Fusion Layer into the architecture of a Convolutional Long Short-Term Memory (ConvLSTM) sequential image prediction network. This approach aims to predict fracture propagations in different fracturing stages of horizontal wells. The proposed model is trained on a sample dataset consisting of 5000 instances of hydraulic fracturing in horizontal wells. The dataset includes crucial data such as fracture propagation images, wellbore perforation images, natural fracture images, pumping schedules, and reservoir properties. The model achieves remarkable results, with an MSE less than 15 × 10−5, a maximum SSIM of 0.93, and an average FMAE less than 48. The research findings demonstrate that this method significantly enhances prediction efficiency and provides new insights for predicting fracture morphology and optimizing fracturing design.

Deep Learning–Based Production Forecasting and Data Assimilation in Unconventional Reservoir

Summary Developing unconventional reservoirs such as shale oil is vital for fulfilling the need for energy consumption in the world. Oil production from shale reservoirs is still the most complicated and uncertain phenomenon because of its complex fracture networking, low matrix porosity, and permeability. Production forecasting is crucial for decision-making and tactical exploitation of subsurface resources during production. Traditional methods, such as the Arps decline model and reservoir simulation methods, face significant challenges in forecasting hydrocarbon production due to the highly nonlinear and heterogeneous nature of rocks and fluids. These methods are prone to substantial deviations in forecasting results and show limited applicability to unconventional reservoirs. Therefore, it is essential to improve the production forecasting capability with the help of a data-driven methodology. The data set for modeling is collected from two prominent shale oil-producing regions, the Eagle Ford and the Bakken. The Bakken data set is used to train and test the models, and the Eagle Ford data set is used to validate the model. The random search method was used to optimize the model parameters, and the window sliding technique was used to find a suitable window size to predict future values efficiently. The combination of different deep learning (DL) methods has designed a total of six hybrid models: gated recurrent unit (GRU), long short-term memory (LSTM), and temporal convolutional network (TCN). These models can capture the spatial and temporal patterns in the oil production data. The results concluded that the TCN-GRU model performed best statistically and computationally compared with other individual and hybrid models. The robust model can accelerate decision-making and reduce the overall forecasting cost.

Life Cycle Optimization of CO2 Huff ’n’ Puff in Shale Oil Reservoir Coupling Carbon Tax and Embedded Discrete Fracture Model

Summary Amidst escalating environmental pressures, energy-intensive industries, particularly the oil and gas sector, are compelled to transition toward sustainable and low-carbon operations, adhering to the constraints of the environmental economy. While conventional reservoirs have been extensively developed, unconventional reservoirs, such as shale reservoirs, are poised to be the focal point in the future. Carbon dioxide enhanced oil recovery (CO2-EOR), a potent development tool proven effective in shale reservoirs, offers substantial carbon storage potential while significantly augmenting production. However, prior studies have solely optimized shale oil CO2-EOR production based on a singular optimization algorithm with net present value (NPV) as the objective function. In this study, we propose a novel NPV concept incorporating a carbon tax, which incorporates carbon taxes regulated by governments or organizations, thereby guiding carbon offsetting in oil reservoirs. We employ the embedded discrete fracture model (EDFM) approach to strike a balance between the accuracy of shale reservoir fracture simulation and computational efficiency, thereby enhancing timely technical guidance in the field. Subsequently, we compare the existing mainstream reservoir optimization algorithms and introduce a novel life cycle CO2 huff ’n’ puff (HnP) optimization workflow based on low-carbon NPV. The optimized NPV of the target reservoir witnessed an increase of 116.30%, while the optimization time was reduced by 89.47%, and the CO2 storage capacity was augmented by 12.58%. The workflow accelerates the simulation of the CO2 HnP in shale reservoirs, optimizing the production efficiency and CO2 storage capacity of shale reservoirs, and facilitating comprehensive and efficient production guidance for the production site.

Numerical simulations of the acoustic and electrical properties of digital rocks based on tetrahedral unstructured mesh

Abstract Unconventional reservoirs typically exhibit strong heterogeneity leading to a significant scale effect in digital rock physics simulations. To ensure the reliability of the simulation results, improving computational efficiency and increasing sample sizes are crucial. In this study, we present a numerical finite element simulation method for the acoustic and electrical properties of digital rock cores based on tetrahedral unstructured meshes. We calculated the elastic moduli and electrical resistivity of the Fontainebleau sandstone digital rock samples. A comparison was made between the tetrahedral mesh and the traditional voxel-based hexahedral mesh in terms of the accuracy and efficiency of finite element numerical simulations. The results indicate that this numerical simulation method based on the tetrahedral mesh exhibits high accuracy comparable to experimental results, and its computational efficiency is significantly improved compared to the traditional hexahedral mesh method. These findings highlight the advantages of this finite element simulation method in improving the computational scale and efficiency of digital rock simulations. It effectively addresses common computational resource constraints in dealing with large-scale core systems and facilitates better integration with engineering construction, well-logging instrument simulations, and production applications.

Molecular Insights into Soaking in Hybrid N2-CO2 Huff-n-Puff: A Case Study of a Single Quartz Nanopore-Hydrocarbon System.

Hybrid N2-CO2 huff-n-puff (HnP) has been experimentally demonstrated to be a promising approach for improving oil recovery from tight/ultratight shale oil reservoirs. Despite this, the detailed soaking process and interaction mechanisms remain unclear. Adopting molecular dynamic simulations, the soaking behavior of hybrid N2-CO2 HnP was investigated at the molecular and atomic levels. Initially, the soaking process of fluid pressure equilibrium after injection pressure decays in a single matrix nanopore connected to a shale oil reservoir is studied. The study revealed that counter-current and cocurrent displacement processes exist during the CO2 and hybrid N2-CO2 soaking, but cocurrent displacement occurs much later than counter-current displacement. Although the total displacement efficiency of the hybrid N2-CO2 soaking system is lower than that of the CO2 soaking system, the cocurrent displacement initiates earlier in the hybrid N2-CO2 soaking system than in the CO2 soaking system. Moreover, the N2 soaking process is characterized by only counter-current displacement. Next, the soaking process of fluid pressure nonequilibrium before the injection pressure decays is investigated. It was discovered that counter-current and cocurrent displacement processes initiate simultaneously during the CO2, N2, and hybrid N2-CO2 soaking process, but cocurrent displacement exerts a dominant influence. During the CO2 soaking process, many hydrocarbon molecules in the nanopore are dissolved in CO2 while simultaneously exhibiting a substantial retention effect in the nanopore. After pure N2 injection, there is a tendency to form a favorable path of N2 through the oil phase. The injection of hybrid CO2-N2 facilitates the most significant cocurrent displacement effect and the reduction in residual oil retained in the nanopore during the soaking process, thus resulting in the best oil recovery. However, the increase rate in total displacement efficiencies of the different soaking systems over time (especially the hybrid N2-CO2 soaking system) was significantly larger before than after injection pressure decays. Additionally, the displacement effect induced by oil volume swelling is significantly restricted before the injection pressure decays compared to the soaking process after the injection pressure decays. This study explains the role of CO2-induced oil swelling and N2-induced elastic energy played by hybrid N2 and CO2 at different stages of the hybrid N2-CO2 soaking process before and after pressure decays and provides theoretical insights for hybrid gas HnP-enhanced recovery. These pore-scale results highlight the importance of injection pressure and medium composition during the soaking process in unconventional oil reservoirs.

Permeability Evolution of Shale during High-Ionic-Strength Water Sequential Imbibition

It is widely accepted in the oil and gas industry that high-ionic-strength water (HISW) can improve oil and gas recovery in unconventional shale reservoirs by limiting shale hydration. Despite numerous supporting studies, there is a lack of a systematic analysis exploring the effect of HISW on shale permeability evolution, particularly considering varying chemical compositions. In this work, we investigated the impact of different concentrations of NaCl and CaCl2 on shale permeability through sequential HISW imbibition experiments, beginning with the highest NaCl and lowest CaCl2 concentrations. After maintaining the highest effective stress for an extended period, significant permeability reduction and potential fracture generation were observed, as indicated by periodic fluctuations in differential pressure. These effects were further intensified by displacements with HISW solutions. Advanced post-experimental analyses using micro-CT scans and SEM-EDS analysis revealed microstructural changes within the sample. Our findings offer initial insight into how HISW-shale interactions influence shale permeability, using innovative approaches to simulate reservoir conditions. The findings indicate that discrepancies in the chemical composition between injected solutions and shale may lead to shale disintegration during hydraulic fracturing processes.

Level of thermal maturity estimation in unconventional reservoirs using interval inversion and simulating annealing method

AbstractThis study presents a novel geophysical approach for estimating the level of thermal maturity (LOM) in unconventional hydrocarbon reservoirs using well log data. LOM is a crucial parameter for assessing the hydrocarbon generation potential of source rocks, but it traditionally relies on laboratory measurements of core samples, which can be time-consuming and costly. The proposed method combines two techniques: interval inversion for estimating total organic carbon (TOC) content from well logs and simulated annealing (SA) optimization for deriving LOM from the estimated TOC. The interval inversion method enables accurate TOC estimation by jointly interpreting multiple well logs over depth intervals, overcoming limitations of conventional point-by-point inversion. Using the estimated TOC, the SA algorithm optimizes an energy function related to Passey's empirical TOC-LOM relationship, iteratively finding the optimal LOM value that best fits the well log data. This approach provides a continuous in situ LOM profile along the borehole without requiring core measurements. The effectiveness of the method is demonstrated through case studies on datasets from the North Sea (Norway), the Pannonian Basin (Hungary), and the Kingak Formation (Alaska). The LOM estimates show good agreement with reported maturity levels and allow reliable reservoir characterization. Statistical analysis confirms the robustness and accuracy of the results. By reducing dependence on core data, this integrated inversion-optimization workflow streamlines the reservoir prospecting phase, enhancing operational efficiency. The method holds promising applications across diverse geological settings for cost-effective evaluation of unconventional hydrocarbon plays.

Realizing the Efficient Dissolution of Drag Reducer upon pH-Induced Demulsification of Inverse Polymer Emulsion.

The increasing exploitation of fossil resources needs to shift people's attention to developing unconventional reservoir resources. Polyacrylamide-based emulsion drag reducers can effectively reduce the turbulence of fracturing fluid and improve oil recovery, but their release effect is poor, which limits their practical application. Here, we constructed a pH-responsive inverse polymer emulsion of poly(acrylamide-2-acrylamido-2-methylpropanesulfonic acid). Interestingly, HOA/Tween 80 exhibits remarkable pH-responsive behavior, which enables the monomer emulsion to change the type of emulsion under pH stimulation. Our results propose that the P(AM-AMPS) polymer emulsion is eluted with the same aqueous phase as the W/O P(AM-AMPS) polymer emulsion, thereby achieving the effect of drag reduction. P(AM-AMPS) can be rapidly released from the inverse polymer emulsion within 70 s upon pH stimulation, the drag reduction rate of which was 60.4%. Obviously, the inverse polymer emulsion prepared by a pH-responsive surfactant not only has good stability but also can achieve rapid release of the polymer upon pH stimulation, which supplies an interesting indication to explain why a balance exists between the stability of the emulsion and release of P(AM-AMPS).

A molecular dynamics investigation into the polymer tackifiers in supercritical CO2 fracturing fluids under wellbore conditions

SC-CO2 fracturing technology is a feasible method for green extraction of unconventional oil and gas reservoirs. However, due to a series of problems such as sand transportation during SC-CO2 fracturing, CO2 thickening has become the focus of current research. Polymer thickeners have been widely used in oilfields. Due to the macroscopic nature and limitations of laboratory experiments, we have not been able to elucidate the microscopic mechanism of polymer thickening CO2 and the viscosity change of the CO2 fracturing fluid system downhole after polymer addition. In this study, we used all-atom modeling and molecular simulation of the COMPASSII force field. We selected nine polymers to study their microscopic properties and the factors affecting their effects. Finally, we simulated the viscosity change of the CO2 system after the addition of polymer tackifiers in the wellbore under the CO2 fracturing construction conditions by combining the data from one well in the oilfield.

Experimental study on pore structure evolution of thermally treated shales: implications for CO2 storage in underground thermally treated shale horizons

Extracting gas from unconventional shale reservoirs with low permeability is challenging. To overcome this, hydraulic fracturing (HF) is employed. Despite enhancing shale gas production, HF has drawbacks like groundwater pollution and induced earthquakes. Such issues highlight the need for ongoing exploration of novel shale gas extraction methods such as in situ heating through combustion or pyrolysis to mitigate operational and environmental concerns. In this study, thermally immature shales of contrasting organic richness from Rajmahal Basin of India were heated to different temperatures (pyrolysis at 350, 500 and 650 °C) to assess the temperature protocols necessary for hydrocarbon liberation and investigate the evolution of pore structural facets with implications for CO2 sequestration in underground thermally treated shale horizons. Our results from low-pressure N2 adsorption reveal reduced adsorption capacity in the shale splits treated at 350 and 500 ºC, which can be attributed to structural reworking of the organic matter within the samples leading to formation of complex pore structures that limits the access of nitrogen at low experimental temperatures. Consequently, for both the studied samples BET SSA decreased by ∼58% and 72% at 350 °C, and ∼67% and 68% at 500 °C, whereas average pore diameter increased by ∼45% and 91% at 350 °C, and ∼100% and 94% at 500 °C compared to their untreated counterparts. CO2 adsorption results, unlike N2, revealed a pronounced rise in micropore properties (surface area and volume) at 500 and 650 ºC (∼30%–35% and ∼41%–63%, respectively for both samples), contradicting the N2 adsorption outcomes. Scanning electron microscope (SEM) images complemented the findings, showing pore structures evolving from microcracks to collapsed pores with increasing thermal treatment. Analysis of the SEM images of both samples revealed a notable increase in average pore width (short axis): by ∼4 and 10 times at 350 °C, ∼5 and 12 times at 500 °C, and ∼10 and 28 times at 650 °C compared to the untreated samples. Rock-Eval analysis demonstrated the liberation of almost all pyrolyzable kerogen components in the shales heated to 650 °C. Additionally, the maximum micropore capacity, identified from CO2 gas adsorption analysis, indicated 650 °C as the ideal temperature for in situ conversion and CO2 sequestration. Nevertheless, project viability hinges on assessing other relevant aspects of shale gas development such as geomechanical stability and supercritical CO2 interactions in addition to thermal treatment.

A Comparative Study of Surfactant Solutions Used for Enhanced Oil Recovery in Shale and Tight Formations: Experimental Evaluation and Numerical Analysis.

Applying chemical enhanced oil recovery (EOR) to shale and tight formations is expected to accelerate China's Shale Revolution as it did in conventional reservoirs. However, its screening and modeling are more complex. EOR operations are faced with choices of chemicals including traditional surfactant solutions, surfactant solutions in the form of micro-emulsions (nano-emulsions), and nano-fluids, which have similar effects to surfactant solutions. This study presents a systematic comparative analysis composed of laboratory screening and numerical modeling. It was conducted on three scales: tests of chemical morphology and properties, analysis of micro-oil-displacing performance, and simulation of macro-oil-increasing effect. The results showed that although all surfactant solutions had the effects of reducing interfacial tension, altering wettability, and enhancing imbibition, the nano-emulsion with the lowest hydrodynamic radius is the optimal selection. This is attributed to the fact that the properties of the nano-emulsion match well with the characteristics of these shale and tight reservoirs. The nano-emulsion is capable of integrating into the tight matrix, interacting with the oil and rock, and supplying the energy for oil to flow out. This study provides a comprehensive understanding of the role that surfactant solutions could play in the EOR of unconventional reservoirs.

Evaluation of CO2-enhanced gas recovery and storage through coupled non-isothermal compositional two-phase flow and geomechanics modelling

CO2 injection into unconventional gas reservoir has been recognized as a promising approach to enhance unconventional gas recovery (CO2-EUGR) and sequester CO2 geologically. The CO2-EUGR is a complex multi-physics coupling process. To accurately assess the effectiveness of different injection strategies, this paper firstly presents a non-isothermal compositional two-phase flow model coupling with geomechanics, in which a multicomponent adsorption kinetics is incorporated to separate free phase and adsorbed phase. A hybrid numerical approach combining EbFVM and GFEM is used for numerical solutions. The performance of different injection strategies for CO2-EUGR is evaluated. The results indicate that CO2 injection is able to improve CH4 recovery significantly, over 90 % of injected CO2 can be adsorbed in reservoirs, The performance of CO2-EUGR is permeability dependent, the displacement effect occurs earlier when reservoir permeability is higher; Increase in temperature of injected gas and mixed CO2/N2 injection can further improve CH4 recovery, especially for low permeability gas reservoirs; Mixed gas injection also enables displacement effect to occur earlier; Cyclic injection can hardly lead to increase in CH4 production, especially when reservoir permeability is higher, while it can cause an increase in amount of adsorbed CO2 during injection period. Based on these findings, a geothermal-assisted CO2-EUGR method is proposed.

Numerical simulations on compression behaviors of the laminated shale based on the digital image technology and the discrete element method

As an unconventional reservoir sedimentary rock, shale contains a series of layers and various microstructures that lead to complex mechanical properties, such as the anisotropy of stiffness and strength. This study is directed towards the anisotropy caused by the microstructures of the shale, employing the 2D particle flow code (PFC2D) to explore stiffness, strength, failure mode, and micro-crack evolution. More realistic microstructures and the calibration of microscopic parameters of the shale are reasonably considered through the computed tomography (CT) images and mineral analysis. The corresponding numerical simulation results are fully compared with the experimental results. In what follows, the sensitivity analysis is conducted on the key microscopic parameters and microstructure characteristics in numerical samples with laminated characteristics. The results show that the influence of microscopic parameters of the parallel bonding model on macroscopic parameters is related to the layering angle and the face type, and the microstructures and initial cracks of numerical samples can considerably affect the macroscopic mechanical behaviors of the laminated samples. Next, the effect of confining pressure on the mechanical properties of layered shale is also discussed based on the numerical results. These findings highlight the potential of this approach for applications in micro-scaled models and calibration of microscopic parameters to probe mechanical behaviors of the laminated rock.

Elastic and anisotropic properties of organic‐rich lacustrine shales: An experimental study

AbstractExperimental investigation of the elastic behaviours of lacustrine shales remains sparse, although they play an essential role in source rock evaluation, unconventional reservoir exploration and development, and the seal integrity evaluation for geological storage of CO2 and nuclear waste disposal. We make the ultrasonic velocity measurement of 63 organic‐rich shale samples (Chang 7, Qingshankou and Lucaogou formation) from three typical lacustrine basins in China. It is found that the P‐ and S‐wave velocity of Chang 7 and Qingshankou shale corresponding to the fresh‐brackish lacustrine depositional environment is mainly impacted by the clay and organic matter content, whereas their elastic anisotropic magnitude is mostly influenced by clay content. The P‐ and S‐wave velocities of Lucaogou shale corresponding to the saline lacustrine depositional environment are mainly affected by the total organic carbon and porosity and exhibit weak anisotropy linked to organic matter enrichment. Exponential law well captures the relationship between anisotropic magnitude and velocity perpendicular to bedding for both saline and fresh‐brackish water lacustrine shales, although there exists notable discrepancy, particularly at low velocities. The disparity in elasticity between laminations has a profound impact on the magnitude of elastic anisotropy and shapes the trend of velocity variations.

Experimental Study on Proppant Migration in Fractures Following Hydraulic Fracturing

Complex fracture technology is key to the successful development of unconventional oil and gas reservoirs, such as shale. Most current studies focus on how to improve the complexity of the fracture network. It is still unclear whether proppant can enter the branch fractures at all levels after the formation of complex fractures. The effects of construction displacement, proppant particle size, proppant density, fracturing fluid viscosity, sand ratio, and other factors on proppant migration in single fractures and complex fractures were studied using an experimental device independently developed by the laboratory. The results show that the lowest point height of the sandbank and the equilibrium height of the sandbank are directly proportional to the particle concentration and density, respectively, and inversely proportional to the displacement and fracturing fluid viscosity. The equilibrium time of the sandbank is inversely proportional to the displacement, particle concentration, and density, respectively, and proportional to the viscosity of the fracturing fluid. Under the same experimental conditions, the larger the branch angle, the smaller the height of the main/secondary fracture sandbank. In the design of the fracturing process, fracturing fluid with varying viscosities and proppant with different densities should be selected according to the formation conditions and fracturing targets. In the face of long fracture lengths, the combination of low-viscosity fracturing fluid with an appropriate viscosity and low-density proppant can meet the goal of placing proppant over long distances and effectively supporting fractures over extended lengths. Subsequently, high-density proppant or reduced construction displacement are adopted to usefully support fractures in the near-wellbore area. The results of this paper can provide theoretical support for proppant selection and fracturing program design.

Study on Foaming Agent Foam Composite Index (FCI) Correlation with High Temperature and High Pressure for Unconventional Oil and Gas Reservoirs

In the process of unconventional oil and gas reservoir exploitation, it is difficult to reduce drilling fluid lost in natural fractures, enhance the CO2 displacement effect and reduce foam drainage gas recovery costs. In most cases, foaming agents can solve these problems in a low-cost way in a short period of time. Foaming agent screening and evaluation is the key to this technology. However, there are few experimental tests used in the evaluation of foaming agent properties that match the actual unconventional oil or gas well conditions of high temperature and high pressure. Using the actual temperature and pressure conditions of a wellbore, the foaming capacity and half-life of two common foaming agents were systematically evaluated by using the high-temperature and high-pressure visual foam properties evaluation device (UPMX-500), in which the foaming agent’s volume concentration was 3‰ in a simulated formation water with a pH of 6 and salinity of 9 × 104 mg/L. The high-temperature (40 °C, 60 °C, 80 °C, 100 °C) and high-pressure (0.1 MPa, 6.0 MPa, 8.0 MPa, 10.0 MPa) effect on the foaming capacity and half-life was analyzed. Binary linear regression of pressure and temperature was carried out, taking the foam composite index as the target and using a formula with high correlation. The results showed that the foam composite index (FCI) of the two foaming agents was positively correlated with pressure and temperature. The correlation of UT-7 was FCI = 64.1196T + 735.713p − 2066.2, the correlation of HY-3K was FCI = 62.5523T + 7220.391p − 2415.6, and the coefficients of determination were 0.9799 and 0.9895, respectively, with an error of less than 10%. This correlation equation can provide a reference for accurately predicting the foaming capacity of foaming agents under high-temperature and high-pressure conditions and can also be used to optimize foaming agents or to qualitatively evaluate results for the efficient exploitation of unconventional oil and gas reservoirs.

Experimental investigation of zwitterionic surfactant for enhanced oil recovery in unconventional reservoir: A study in the middle bakken formation

Some surfactants may not be effective in harsh reservoir environments because of their tendency to precipitate in high salinity and high temperature conditions. However, Zwitterionic surfactants are considered more tolerant to salinity and temperature. This study investigates the ability of zwitterionic surfactants to improve oil recovery in tight core samples obtained from the Middle Bakken (MB) Formation in North Dakota. The Laboratory tests to determine the efficacy of three betaine zwitterionic surfactants were carried out at a temperature of 90 °C and a high salinity formation brine of 29 wt% to simulate oil recovery under Bakken reservoir conditions. Before the imbibition experiment, the samples underwent petrophysical investigation, and the mineral compositions were determined using the XRD method. The three surfactant samples ME1, CD 2, and CG 3 applied in the study consistently changed the wetting condition of Bakken cores from contact angle of 143.2° to a range of 32°-42°, indicating changing from oil-wet to water-wet. The result obtained shows that the interfacial tension (IFT) between brine and crude oil was reduced from 34.5 mN/m to 8.9 × 10−1 mN/m, 1.19 mN/m, and 2.49 mN/m, respectively, at a critical micelle concentration (CMC) of 0.05 %. The surfactants demonstrated a significantly higher ability to recover oil from the core samples compared to the use of brine only. The imbibition experiments revealed an extra oil recovery of 16.4 % at CMC. Thus, the imbibition of surfactant formulations offers significant potential for enhancing oil recovery in the Bakken Formation.

Impact of surfactants used in oil and gas extraction on produced water treatment by membrane distillation

Produced water from unconventional oil and gas reservoirs often contains non-ionic surfactants that are added to the hydraulic fracturing fluid to facilitate water release and enhance gas production. This study investigates the impact of currently used surfactants (i.e., nonylphenol ethoxylates (NPEOs) and octylphenol ethoxylates (OPEOs)) and proposed alternative surfactants on the performance of membrane distillation (MD) for produced water treatment. The impact of NPEOs and OPEOs on wetting of PTFE membranes was studied as a function of their concentrations and ethoxylate (EO) chain length in a lab-scale DCMD system. Additionally, alternative surfactants, including linear alcohol ethoxylates (LAEs), branched secondary alcohol ethoxylates (BAEs), and alkyl polyglycosides (APGs), were evaluated for their potential to replace NPEOs and OPEOs. Experimental results indicate that the increase in the number of EO units in NPEOs decreased their tendency to cause membrane wetting by reducing their interaction with hydrophobic surfaces. It was also observed that LAEs and APGs that are environmentally friendly alternatives did not cause membrane wetting. This study provides valuable insights into the underlying mechanisms of surfactant-membrane interactions and offers guidelines for surfactant alternatives that can potentially improve hydraulic fracturing and lower environmental concerns while facilitating the use of MD for produced water treatment and recovery.

Performance of the Petroleum Reservoir Under Waterflooding at the Petrochad Field in Mangara-Chad

The Mangara petroleum field is made up of three superimposed reservoirs (C, D, E) with approximately 2500 m depth. These are unconsolidated sandstone reservoirs with an underlying active aquifer. The petrophysical properties of the reservoirs are relatively good as it’s a self-sourced unconventional reservoir based on its organic richness characteristics unconventional resource opportunity as tight carbonate reservoir. Tank pressure is approximately 2900 psi, for an average temperature of 180°F. Of the 50 wells initially drilled, 23 are currently producing. The pressure is support by 04 injector wells, and daily production is estimated at approximately 12,000 bbl/d. To maximize oil production and minimize water production, the positions of injection wells were moved, which permitted to reduce the number of producing wells from 23 to 18. The result revealed that this scheme can maintained the pressure at desired levels of 2900 psi, until year 2040 and reversed the current trend in water production, which was 14,000 bbl/d. In the predicted scenarios, cumulative production will be maintain at 25,000 bbl/d with a daily production of around 18,000bbl of oil compared to formerly figure of 7000 bbl of water until 2040.

A Heterogeneous Viscosity Flow Model for Liquid Transport through Nanopores Considering Pore Size and Wettability.

The confinement effect in micro- and nanopores gives rise to distinct flow characteristics in fluids. Clarifying the fluid migration pattern in confined space is crucial for understanding and explaining the abnormal flow phenomena in unconventional reservoirs. In this study, flow characteristics of water and oil in alumina nanochannels were investigated with diameters ranging from 21 nm to 120 nm, and a heterogeneous viscosity flow model considering boundary fluid was proposed. Compared with the prediction of the HP equation, both types of fluids exhibit significant flow suppression in nanochannels. As the channel size decreases, the deviation degree increases. The fluid viscosity of the boundary region displays an upward trend as the channel size decreases and the influence of the interaction between the liquid and solid walls intensifies. The thickness of the boundary region gradually decreases with increasing pressure and eventually reaches a stable value, which is primarily determined by the strength of the interaction between the liquid and solid surfaces. Both the pore size and wettability are essential factors that affect the fluid flow. When the space scale is extremely small, the impact of wettability becomes more pronounced. Finally, the application of the heterogeneous flow model for permeability evaluation has yielded favorable fitting results. The model is of great significance for studying the fluid flow behavior in unconventional reservoirs.