Sand Pack Research Articles

The Potential of Crab Chitosan Polymer as EOR Injection Fluid

The abundant availability of crab shell waste in Indonesia is still not optimally utilized. Crab shell contains chitin that can be processed into chitosan. Chitosan polymer can be developed to be utilized on Enhanced Oil Recovery. The objective of this study is to measure the amount of biopolymer adsorption potential of crab shell on sandstone both statically and dynamically, in order to obtain oil recovery potential by using crab shell chitosan as injection fluid. Method of this study is categorized as experimental research through direct observation inside a laboratory. The utilized biopolymer in this research was chitosan made from crab shell. Biopolymer solution concentrations in this research are 5,000, 10,000, and 15,000 mg/L and the formation water salinity levels were at 10,000 and 20,000 mg/L. The research was conducted by using variations of formation water compounds namely NaCl and MgCl2. The research conducted consists of viscosity, transmittance, and adsorption measurements on biopolymer and water formation salinity concentrations. The sand pack flooding was conducted to observe oil displacement by selected formation water and chitosan solution. After conducted viscosity test, solution with the highest viscosity levels were chosen as driving fluid in sand pack flooding. The solutions are N2R3 samples which are crab shell chitosan solution with formation water containing NaCl with salinity level 20,000 mg/L and chitosan concentration of 15,000 mg/L. The viscosity value of the sample was at 1728.67 cP. Conclusion: Crab chitosan with 15,000 mg/L concentration, 20,000 mg/L salinity, and viscosity value of 1728.67 cp can be optimally utilized in sand pack flooding by providing incremental recovery factor of 10.27%.

Outdoor access practices in the Canadian dairy industry

Dairy cows are highly motivated to access pasture and have a partial preference for alternative forms of outdoor access (e.g., deep-bedded outdoor sand or wood-chip packs). In addition, Canadians value the provision of outdoor access to dairy cows as they perceive it as important for good cow welfare. In contrast to Europe, Oceania, and the USA, little data exist on the use of outdoor access on Canadian dairy farms. Therefore, our objective was to assess current outdoor access practices for dairy cows in Canada. An online questionnaire was used to determine housing and outdoor access practices for lactating cows, dry cows, pregnant heifers, and weaned, nonpregnant heifers on Canadian dairy farms. The questionnaire was distributed by the 10 provincial milk boards between November 2020 and August 2021, resulting in an 8.9% response rate (n = 903 completed questionnaires). In total, 75% (n = 675) of respondents provided some form of outdoor access to at least 1 cattle class on their farm. Pasture was the most frequently used form of outdoor access for all cattle classes. A total of 28 and 44% of Canadian dairy farms provided lactating and dry cows, respectively, access to pasture whereas for youngstock, these numbers were 44 and 24% for pregnant heifers and weaned, nonpregnant heifers, respectively. Herd size (for each cow class), indoor housing system, and region were all associated with the provision of pasture. Farms with larger lactating herds less often provided access to pasture; larger herd sizes in terms of weaned, nonpregnant heifers, pregnant heifers, and dry cows were also associated with a lower likelihood of access to pasture. Farms using indoor bedded pack housing for their lactating cows more often provided pasture to this cattle class than farms with freestall or tiestall housing; this likelihood did not differ between farms with tie or freestall housing for this cattle class. Dry cows or pregnant heifers housed in a tiestall were more often provided pasture than freestall-housed dry cows or pregnant heifers. Housing type for weaned, nonpregnant heifers was not associated with the likelihood of pasture provision. Farms in British Columbia or on Canada's East Coast (i.e., Nova Scotia, New Brunswick, and Prince Edward Island) more often provided lactating cows pasture compared with farms in other regions. For the other 3 cattle classes, farms on the East Coast of Canada more often provided pasture than farms in other parts of Canada. These results will inform future decisions regarding outdoor access for Canadian dairy cattle and may also aid in identifying future areas of research. For example, our results may aid in designing housing systems that facilitate outdoor access in larger herds and in areas that are subject to more extreme weather conditions.

Comprehensive analysis of the effect of reservoir key parameters on the efficacy of DTPA chelating agent in minimizing interfacial tension and enhanced oil recovery

Chelating agents reduce the salinity of seawater (SW) and mimic low salinity water (LSW) by binding metal ions in the solution and on the rock surface. This process decreases SW dilution costs and prevents scale formation while improving oil recovery without damaging the reservoir. This study investigates the impact of Diethylenetriaminepentaacetic acid (DTPA) chelating agent on the reduction of interfacial tension (IFT) between oil and SW, without the use of additional chemicals. For the first time, we comprehensively analyzed how reservoir key parameters (concentration, salinity, temperature, and pH) affect the performance of DTPA in reducing IFT. Additionally, rock wettability alteration and sand pack flooding experiments were conducted to evaluate the effect of DTPA on rock wettability and oil recovery. The results revealed that increasing the temperature to 75 °C and the concentration of DTPA to 5 wt% resulted in an IFT reduction to less than 1 mN/m, making the oil miscible in the DTPA solution. Salinity studies demonstrated that by increasing the solution salinity up to the optimal level, the IFT of oil/brine decreased. Furthermore, using 5 wt% DTPA solution altered the rock/oil contact angle from 143° (oil-wet) to 23° (strongly water-wet), highlighting the effect of DTPA on rock wettability alteration. Based on these findings, 5 wt% DTPA was selected as the optimal concentration, resulting in an increase in oil recovery up to 20.3% of original oil in place (OOIP) after SW injection. Elemental analysis of DTPA flooding effluent also confirmed the chelation of metal ions from rock and solution.

Dynamic monitoring of saturation profiles during two phase immiscible displacements in confined sand packs using time-domain analysis of the frequency domain electromagnetic sweeps

Water saturation 1D spatial profiles were monitored using real-time domain analysis of the measured frequency domain complex reflection coefficients of electromagnetic sweeps during oil and deionized water flood experiments at ambient conditions. Gravity and viscous induced fingering and piston-like displacement scenarios were explored. A patented coaxial transmission line core holder was designed to host saturated sand packs compressed in their axial and radial dimensions. An inverse chirp z-transform algorithm was used to convert the measured responses from frequency to time domain. An optimization routine was developed to convert the resulting time domain step responses to water saturation profiles at every pore volume fraction of fluids injected. Advancing and trailing fronts and their breakthrough times were detected. Darcy's flow analysis was performed to extract 1D pressure distribution spatial profiles and dynamic capillary pressure curves for 3 drainage floods. The oil ganglia flow and gravity fluid separation were detected in water floods.

Microbial communities succession post to polymer flood demonstrate a role in enhanced oil recovery.

The role of indigenous microbial communities in residual oil extraction following a recovery process is not well understood. This study investigated the dynamics of resident microbial communities in oil-field simulating sand pack bioreactors after the polymer flooding stage resumed with waterflooding and explored their contribution to the oil extraction process. The microbial community succession was studied through high-throughput sequencing of 16S rRNA genes. The results revealed alternating dominance of minority populations, including Dietzia sps., Acinetobacter sps., Soehngenia sps., and Paracoccus sps., in each bioreactor following the flooding process. Additionally, the post-polymer waterflooding stage led to higher oil recovery, with hydroxyethylcellulose, tragacanth gum, and partially hydrolyzed polyacrylamide polymer-treated bioreactors yielding additional recovery of 4.36%, 5.39%, and 3.90% residual oil in place, respectively. The dominant microbial communities were previously reported to synthesize biosurfactants and emulsifiers, as well as degrade and utilize hydrocarbons, indicating their role in aiding the recovery process. However, the correlation analysis of the most abundant taxa showed that some species were more positively correlated with the oil recovery process, while others acted as competitors for the carbon source. The study also found that higher biomass favored the plugging of high permeability zones in the reservoir, facilitating the dislodging of crude oil in new channels. In conclusion, this study suggests that microbial populations significantly shift upon polymer treatment and contribute synergistically to the oil recovery process depending on the characteristics of the polymers injected. KEY POINTS: • Post-polymer flooded microbial ecology shows unique indigenous microbial consortia. • Injected polymers are observed to act as enrichment substrates by resident communities. • The first study to show successive oil recovery stage post-polymer flood without external influence.

Dynamic monitoring of dielectric properties during two phase immiscible displacements in sand packs using frequency domain electromagnetic sweeps

Electromagnetic heating is a promising soil remediation method especially in thin formations. The lack of a wide-spread adoption of this method stems from insufficient knowledge of how the complex dielectric properties, that govern propagation of the electromagnetic waves through porous media, change with changing frequency, water saturation, displacement types and flow regimes. To breach these gaps several sets of spontaneous deionized (DI) water imbibition experiments, followed by the primary drainage floods, that were followed by the secondary DI water imbibition floods in confined uniform sand packs were performed. The frequency domain relative dielectric constant and conductivities were extracted from the two-port complex S-parameter measurements taken with the vector network analyzer during these immiscible displacements at various water saturation levels at ambient conditions. A novel coaxial transmission line core holder was designed and commissioned, and a modified version of a plane-invariant dielectric extraction algorithm was developed for this purpose. Series, parallel and semi-disperse mixing models were applied to fit the water saturation dependent relative dielectric constant and conductivity values sampled at 500 MHz from the extracted frequency domain spectra. The Maxwell-Garnett parallel model was proved to be the most flexible because it could capture the sampled conductivity values in all secondary imbibition floods before and after the breakthroughs, where the inflection points were observed. These inflection points were attributed to silica production and a potential shear-stripping flow. This observation was further confirmed by conducting a single-phase Darcy's law analysis of two DI water imbibition floods.

Insights into Enhanced Oil Recovery by Coupling Branched-Preformed Particle Gel and Viscosity Reducer Flooding in Ordinary Heavy Oil Reservoir

Viscosity reducer flooding has been successfully applied in tertiary oil recovery of ordinary heavy oil reservoirs. However, lowering interfacial tension or reducing oil viscosity, which is more critical for viscosity reducer to improve oil recovery of ordinary heavy oil, has not yet formed a unified understanding, which restricts the further large-scale application of viscosity reducer flooding for ordinary heavy oil reservoir. Moreover, when the dominant water flow channel is formed in the reservoir, the sweep efficiency decreases sharply and can affect oil recovery efficiency of viscosity reducer. Therefore, in this study, the concept of branched-preformed particle gel (B-PPG) coupling viscosity reducer flooding is proposed. The oil-water interfacial tension performance, emulsification ability, and viscosity reduction performance of three different viscosity reducers were evaluated. The enhanced oil recovery ability of viscosity reducers, B-PPG, and viscosity reducer/B-PPG composite systems was investigated by performing sand pack flooding experiments. The results show that the oil-water interfacial tensions of the three viscosity reducers S1, S2, and S3 are 0.432 mN·m-1, 0.0112 mN·m-1, and 0.0031 mN·m-1, respectively. S1 with the highest interfacial tension has the best emulsification and viscosity reduction performance, S2 is the second, and S3 is the worst. The lower the interfacial tension, the worse the emulsification stability. The sand pack flooding results show that the incremental oil recovery of viscosity reducer S2 flooding is the largest, 7.5%, followed by S1, 7.3%, and S3, 5.6%. The viscosity reducer S2 with moderate interfacial tension and emulsifying capacity has the best ability to improve the recovery of ordinary heavy oil. The incremental oil recovery of B-PPG is 12.7%, which is significantly higher than that of viscosity reducer flooding. Compared with viscosity reducing flooding, the viscosity reducer/B-PPG composite systems have better enhanced oil recovery capacity. The findings of this study can help for better understanding of enhancing oil recovery for ordinary heavy oil reservoir.

Implications of chemical agents and nanofluids coupled with carbon dioxide to improve oil recovery factor

In this study, we experimentally investigated the effects of chemically enhanced oil recovery methods containing hydrolyzed polyacrylamide (HPAM), surfactant–hydrolyzed polyacrylamide (SHPAM), surfactant nanofluids (SNF), that is, coupled with carbon dioxide (CO2) and water chase injection to measure enhanced oil recovery methods in a sandstone reservoir. To proceed with the experiments, we performed four flooding tests at the simulated reservoir temperature of 70 °C. The sand packs were saturated with oil to establish the irreducible water saturation (Swr). Then, the fluid flow in sand packs remained undistributed for about 5 days to obtain the 1.5 pore volume (PV). We observed that the pressure drop had small fluctuations when there was waterflooding (until 1.5 PV), and after injecting the chemical agents, the pressure drop had a sharp rise. It is indicated that the chemical solution has implemented higher pressure drops (significant energy efficiency) to displace the oil instead of water. The maximum oil recovery factor was about 53% and 59% when HPAM and SHPAM solution displaced oil after waterflooding, respectively; however, it is observed that water chase flooding recovered about 8% and 14% of remaining oil in place while CO2 has increased only 3% and 5%, respectively. SNF solution can provide more oil recovery factors. It is about 72% (SNF with 0.5 wt%) and 67% (SNF with 1 wt%). We observed that water chase flooding recovered about 20% of oil in place while CO2 increased by only 8%. It was concluded that the SNF solution with 0.5 wt% tends to adhere to the water–CO2 and causes to improve oil recovery factor after SNF injection. Therefore, SNF is the optimum enhanced oil recovery method among other chemical agents. On the other hand, with the decrease in CO2 flow rate and increase in silica nanoparticles slug size, pressure drop has started to decrease in higher pore volume injections, indicating that larger volumes of CO2 can be stored in sand packs. However, by increasing the CO2 flow rate and decreasing silica nanoparticles slug size, CO2 can escape easily from the sand pack.

SDBS-Induced Dispersion Effect of High-Rank Coal Fines to Inhibit the Conductivity of Propping Fractures

Coal fines are commonly produced in the form of aggregates during the development of coalbed methane (CBM), which significantly restricts the well productivity. Specifically, the reunion state of coal fines plays a key role in impacting the conductivity of propping fractures after fracturing. In this work, the anionic surfactant sodium dodecyl benzene sulfonate (SDBS) was selected to control the reunion state of coal fines. Visualized simulations of coal fines’ transport behavior in proppants with different particle sizes were carried out under low constant pressure based on sand pack experiments. Moreover, the characteristics of coal fine filling and production in propping fractures were obtained. The results indicate that SDBS has a dispersion effect on coal fine aggregates in the KCl fracturing fluid, with an average reduction of 36% in particle size. There is a positive correlation between the proppant size and the permeability coefficient of propping fractures. Coal fines reduce the permeability coefficients obviously, which first rapidly decrease and then slowly reach a stable stage. In the first stage, the changes of permeability coefficients are affected by the relative particle sizes of the proppant and the coal fine, which is consistent with the classic 1/3 sealing mechanism. In the second stage, SDBS increases the amount of coal fines between the proppant pore throats, and the thickness of the filter cake formed from coal fines at the entrance of the propping fracture increases, resulting in the inhibition of fracture conductivity. Additionally, the output of coal fines is increased dramatically induced by SDBS. Finally, the inhibitory effect of SDBS on fluid production was verified by comparing the water production and coal fine content of two field wells CW # 1 and CW # 2. This study has guiding significance for the output and control of coal fines in low-pressure production of CBM wells.

Deep learning for diffusion in porous media

We adopt convolutional neural networks (CNN) to predict the basic properties of the porous media. Two different media types are considered: one mimics the sand packings, and the other mimics the systems derived from the extracellular space of biological tissues. The Lattice Boltzmann Method is used to obtain the labeled data necessary for performing supervised learning. We distinguish two tasks. In the first, networks based on the analysis of the system’s geometry predict porosity and effective diffusion coefficient. In the second, networks reconstruct the concentration map. In the first task, we propose two types of CNN models: the C-Net and the encoder part of the U-Net. Both networks are modified by adding a self-normalization module [Graczyk et al. in Sci Rep 12, 10583 (2022)]. The models predict with reasonable accuracy but only within the data type, they are trained on. For instance, the model trained on sand packings-like samples overshoots or undershoots for biological-like samples. In the second task, we propose the usage of the U-Net architecture. It accurately reconstructs the concentration fields. In contrast to the first task, the network trained on one data type works well for the other. For instance, the model trained on sand packings-like samples works perfectly on biological-like samples. Eventually, for both types of the data, we fit exponents in the Archie’s law to find tortuosity that is used to describe the dependence of the effective diffusion on porosity.

Clogging and permeability reduction dynamics in porous media: A numerical simulation study

The dynamics of fine particle entrainment, transport, and deposition within pore systems, and in particular, the capacity for mobile fines to impair permeability within porous media is critical in many industrial applications. Considerable effort has been expended over the past several decades to identify and parametrize the governing factors that control permeability reduction, with studies employing a combination of physical experimentation and numerical simulation toward this aim. The objective of this work was to numerically investigate the impact of pore space geometry and fine sizes on the clogging dynamics of porous media. The clogging dynamics were characterized by the length of clogging zone (LCZ), the critical throat size of clogging (CTZC), the clogged fraction of throats (CFT), and the permeability reduction (PR). We implemented a computational fluid dynamics-discrete element method (CFD-DEM) numerical framework with a four-way coupling scheme to obtain insights into throat clogging and permeability reduction within heterogeneous porous media utilizing four different monodisperse suspensions. Geometries of porous media were extracted from 3D images of sand packs obtained using micro-computed tomography. The geometries had porosity values ranging from 0.35 to 0.57 and initial permeabilities between 1.35 and 26.32 μm2. CFD-DEM simulations were performed on each geometry four times, varying the injected fine particle size from 5 to 15 μm diameters. Findings indicate that pore systems with tortuosity <1.28 and angles of solid grains orientation larger than 46o tend to have shorter length clogging zones and greater permeability reduction. Furthermore, although systems with porosities higher than 0.48 tend to have a relatively high clogged fraction of throats, they undergo lower permeability reduction. It was also observed that within the studied pore systems, injection of fine particles larger than 7 μm into systems with aspect ratios higher than 2.5, results in a lower fraction of clogged throats. Additionally, for the studied pore networks,< 7 μm fine particles injected into porous media with a large pore body (> 66 μm) and throat (> 22 μm) radii tended to result in larger clogging zones and a greater critical throat size of clogging.

Acrylamide preformed particle gels with movable-crosslinking for conformance control

In order to improve the deformation ability of the preformed gel particles (PPGs), the movable-crosslinking structure was introduced into the gel network. Herein, polyrotaxane cross-linkers were synthesized by a three-step method, and acrylamide and polyrotaxane cross-linkers form gel. The structure of polyrotaxane cross-linkers was characterized by IR, HNMR, and X-ray diffraction. The findings demonstrate the successful insertion of vinyl into cyclodextrin, resulting in the formation of crosslinking points. The gel with movable-crosslinking has better deformation ability, and the breaking elongation of gel is 937%, showing excellent deformation ability Through temperature resistance and salt resistance, it shows that the expansion ratio of gel is higher than that of ordinary gel. The injectability of the gel was investigated and the sand pack plugging test was conducted. The injectivity experiment shows that the gel with movable-crosslinking has positive injectivity, can migrate to the depth of the formation, and has excellent water-plugging effect.

Experimental Study on Water-Rock Interaction Characteristics of Unconsolidated Sandstone during CO2 Multicomponent Thermal Fluid Injection

According to the reservoir characteristics and the current situation of CO2 utilization during thermal recovery in an unconsolidated sandstone heavy oil reservoir, the mechanism and law of porosity and permeability change in an unconsolidated sandstone heavy oil reservoir during CO2+steam and CO2+steam+ sodium alpha-olefin sulfonate (AOS) injection were studied by combining a static monomineral water-rock reaction and a dynamic polymineral sand pack displacement experiment. In the static water-rock reaction between CO2 and monomineral of reservoir rock, the dissolution degree of monomineral at 200°C is greater than that at 100°C and 300°C, and the order of mineral dissolution is illite, montmorillonite, kaolinite, and quartz. Besides, the dissolution rate of single rock minerals decreased significantly in the system of CO2 with AOS. In the polymineral sand pack displacement experiment, the porosity gradually decreases by CO2 multicomponent thermal fluid, and the permeability first decreases and then increases by CO2 multicomponent thermal fluid, but the permeability change is only about 0.5% by CO2+steam+ AOS, which is mainly attributed to the adsorption of AOS on the rock surface, and it is confirmed in the infrared spectrum of unconsolidated sand after displacement. This also shows that CO2+steam+AOS can stabilize the rock skeleton structure of the reservoir and prevent the deterioration of heterogeneity in the subsequent development of thermal recovery of heavy oil reservoirs; therefore, the CO2 multicomponent thermal fluid with chemical agents can improve the damage of a single CO2 thermal fluid to the reservoir.

Waste plastic derived reduced graphene oxide as a potential additive for the surfactant polymer flooding: A sustainable solution

The twenty-first century's major problems are the demand for sustainable green energy and the eco-friendly upcycling of plastic waste. The solutions to these problems should have an alluring cost-effective industrial synergy. Tackling these issues address the clean energy generation concerns and the long-term preservation of the economy and environment from plastic waste. This study focuses on upcycling waste plastics into reduced graphene oxide (RGO) and their application in enhanced oil recovery. Raman and TEM analysis confirmed the successful synthesis of RGOs. In addition, FTIR helps study the presence of functional groups and TGA for thermal stability analysis. The RGO improves the oil recovery by altering wettability, reducing surface tension / interfacial tension, and minimizing surfactant loss. The surface / interfacial property and wetting attributes of the RGO-based prepared solution were examined by surface tension and contact angle measurement. The surface tension and contact angle reduction using RGO were ∼25% and ∼20% without surfactant. Whereas with surfactant (anionic, cationic, and nonionic) and RGO, the reduction in surface tension was ∼55%, ∼57%, and ∼57%, respectively. Also, the reduction in contact angle with surfactant was ∼83%, ∼46%, and ∼80% for anionic, cationic, and nonionic surfactant with RGO particles. The chemical slug's viscosity was then examined at elevated temperatures. The viscosity results follow the power law model to comprehend fluid flow behavior. Finally, the chemical slug consisting of a surfactant mixture, RGO particles, and an industrial-grade polymer was used in the sand pack flooding studies recovering ∼71% of the original oil in place.

Formulation of Different Polymer Coated Spherules from Granules

A novel spheronisation technique is reported here for forming spherules from granules using FDA approved excipients and common pharmaceutical unit operations. The aspirin is used as a model drug to check stability during the process. For that, spherules are prepared by “bed coating during sliding” (BCDS) of granules. Spherules with two size range (sieve no 20 and 30) are compared. These spherules are further coated with polymers to show the versatility of the process. flow property determination.. Angle of Repose sand packing parameters appeared excellent. Different polymer coating gives different release profile as per the properties of the polymer. However, the drug content is lower for 30 as compared to 20 while drug release profile appears similar. This is a robust and versatile platform delivery system for developing advanced drug delivery systems (ADDS).

Investigation of optimum conditions in gas-assisted gravity drainage using Taguchi experimental design

Gas-assisted gravity drainage (GAGD) is known as an important enhanced oil recovery (EOR) method. Detailed understanding of multiphase fluid flow mechanisms in fractured porous media is one of the challenging issues in reservoir engineering. In this paper, the most effective parameters on the GAGD recovery factor (RF) in fractured porous media are investigated using a new experimental fractured sand pack. The Taguchi method as an effective approach for design of experiments and optimization of design parameters is employed to evaluate impacts of various process variables such as sand particle size, type of wetting and non-wetting phases, gas injection rate, dip angle, and fracture position on oil RF under gravity drainage mechanism. During the experiments, distilled water and condensate are utilized as the wetting-phase. Nitrogen and carbon dioxide are also used as the non-wetting phase. Moreover, an analysis of variance (ANOVA) is conducted to find the most significant parameters affecting GAGD recovery performance. Also, the process variables are optimized to maximize oil RF. The results reveal that the type of wetting phase is the most effective parameter in the GAGD processes. The mean sand size and fracture position are the second and third influencing parameters followed by the injection rate, dip angle, and type of non-wetting phase. The optimum conditions for maximizing RF of the GAGD are identified in the following order: wetting phase of condensate, mean sand size of 300 μm, non-wetting phase of N2, fractures at the number of 3, dip angle equal to 0o (vertical model), and injection rate of 20 cm3/min. According to this research, the average RF of condensate as a wetting phase is found to be around 12% higher than the water case. Also, N2 as an immiscible injected gas causes a higher average RF compared to CO2. Increasing the mean sand size, injection rate, or the number of fractures can enhance the GAGD RF. The dip angle experiments demonstrate the RF of alignment of 0ᵒ or vertical mode is (75.06%) > dip angle of 20ᵒ (71.79%) > dip angle of 5ᵒ (71.60%). The more RF at the dip angle of 20ᵒ in comparison with the 5ᵒ scenario might be due to the capillary continuity and the liquid bridge of the wetting phase from the upper matrix block into the lower one in this specific fractured setup. The experimental results reveal that the emplacement, number, and direction of matrix and fractures play a considerable role in the recovery performance of fractured porous media that should be carefully evaluated in production management plans to obtain a higher final RF in fractured reservoirs.

Experimental study on coal fines migration and effects on conductivity of hydraulic fracture during entire coalbed methane production period

During the dewatering and gas producing stages in coalbed methane (CBM) development, the migration of coal fines in hydraulic fractures substantially threatens the stability and high yield of the gas production process. In this study, three factors—coal fines concentration, coal fines size, and fluid flow rate—were considered to experimentally investigate the migration of coal fines in hydraulic fractures and determine their influence on fracture conductivity during the entire CBM production period. To mitigate the coal fine migration, we experimentally investigated the effectiveness of two types of treatments: physical multistage sand fracturing technology that prevents the coal fines from entering the fracture by utilizing the coal fines barrier, and chemical additives that serve as dispersants or fixed agents. Moreover, a new core preparation method and an efficient fine-coal-fines preparation method were proposed. After injecting the gas bubble in the experiment, a typical strip-type coal-fines distribution was observed in the sand pack, which negatively influenced the gas permeability and gas relative permeability at the gas production stage. Specifically, the conductivity of the sand pack was inversely dependent on the amount of coal fines entering it, and the conductivity rapidly decreased as the mass ratio of the injected coal fines to sand reached 0.625% in the experiment. At the gas production stage, the conductivity of the sand pack injected with a suspension of fine coal fines (<20 μm) was only ∼20% of that injected with a suspension of large coal fines (>20 μm), i.e., finer coal fines could comfortably enter the sand pack and severely reduce its conductivity. Furthermore, a high fluid-flow rate deteriorated the conductivity by driving coal fines through smaller pores, where the possibility of blockage is higher and the formation of coal fines agglomerates is facilitated. Overall, at the gas production stage, the conductivity of the sand pack with a coal fine barrier was 500% higher than that without a coal fine barrier, and the multistage sand fracturing technology delivered appropriate performance in alleviating the conductivity reduction by preventing the migration of finer coal fines into the hydraulic fracture. However, the chemical additives suggested in references, including sodium bicarbonate (NaHCO3) that can affix the coal fines and the fine dispersant sodium lignin sulfonate, delivered inferior performance and even aggravated the conductivity deterioration.

The critical role of core in understanding hydraulic fracturing

Abstract Improved understanding of hydraulic fractures is needed to optimize petroleum well drilling and completion strategies. Yet direct observations of hydraulic fractures are rarely made, and reliance is placed on indirect methods such as microseismic monitoring, interference tests, fibre optic detection of fracturing in adjacent wells and numerical modelling. While these techniques provide useful insights, verification of such studies is commonly lacking; core taken through stimulated intervals offers a robust option for verification. We make the case that core can provide complementary information at a different scale from other data types. Core from a slant well adjacent to two stimulated wells at the Hydraulic Fracture Test Site (HFTS1) in West Texas revealed 375 hydraulic fractures, striking 090°±20°, subparallel to present-day S Hmax . There are more hydraulic fractures than expected, and clustering across a range of scales from approximately 1 cm to 50 m. The largest cluster correlates with high microseismic event density. Diversion, bifurcation, and segmentation structures may account for the large number of fractures observed and the orientation spread. Reactivation of sealed natural fractures and bedding planes is relatively uncommon. Proppant sand packs and patches occur in a few locations, particularly where hydraulic fractures are complex.

A Pore‐Throat Segmentation Method Based on Local Hydraulic Resistance Equivalence for Pore‐Network Modeling

AbstractThe pore network is an approximate representation of the void space of porous materials, such as rocks and soil, via pores (corresponding to large cavities) and throats (narrow constrictions). During extraction of networks from real void space, ambiguous definitions or determinations of pores and throats may cause significant errors in the prediction of single/multi‐phase transport properties. Meanwhile, the pore‐throat segmentation needs to exclude non‐physical parameters as much as possible. In this work, we propose a pore‐throat segmentation method based on local hydraulic resistance equivalence between the real void space and the simplified pore‐throat geometry. Each pore‐throat interface is carefully determined at the position where the simplified tubes preserve the local hydraulic resistance of the real space best. This local segmentation method ensures equivalency between extracted pore network and real pore space without any empirical or non‐physical parameters. After validations of accuracy and reliability by benchmarks, this method is applied to real porous materials including spherical pack, sand pack, sandstone, limestone, and carbonate. The single/two‐phase transport properties predicted by the new method agree well with the experimental data and the direct simulation results. The proposed method improves the accuracy of pore network model (PNM) predictions significantly with a slight increase in computational cost. This local pore‐throat segmentation method may enhance the capability of PNM for more complicated applications.

XANTHAN GUM AND SILICA OXIDE NANOPARTICLE SYNERGIZATION EFFECTS ON OIL RECOVERY

This study aims to evaluate the capability of synergised XG and SiO2 nanoparticles solutions to improve the solution viscosity, IFT reduction and analyse the effects on the recovery factor. Samples were prepared with 4000 ppm XG and five concentrations of SiO2 (1000, 3000, 5000, 7000, 9000 ppm). The samples were tested for viscosity and IFT reduction to determine the optimum concentration of the synergised solution. Then, a flooding test was conducted using a sand pack to measure oil recovery factors when different slug ratios of polymer and brine were injected. Results show viscosity of the solution increased with increasing SiO2 concentrations. The synergy has shown IFT reduction from 75.5 mN/m to 55 mN/m with increasing concentrations of the SiO2 added into the polymer solution. Thus, 4000 ppm of XG synergised with 3000 ppm SiO2 nanoparticles was chosen as the optimum concentration as the IFT reduction is achieved and can be correlated with the viscosity result. A slight viscosity difference is observed when 5000 ppm SiO2 nanoparticles were added to 3000 ppm SiO2 nanoparticles. Oil recovery increased from 27.5% to 56% using 4000 ppm XG, while the oil recovery was increased to 57.5% using the synergised solution with a similar slug ratio. Maximum oil recovery was 66.3%, using an optimum synergised solution with the highest slug ratio of 0.5:0.5 PV polymer flooding to water slug. These prove that SiO2 nanoparticles can help polymer flooding improve sweep and displacement efficiency by viscosity increment and IFT reduction to increase the oil recovery.