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The development of marine gas hydrate from low-permeability offshore reservoirs with serious sand incursion issues is a challenging task. Currently, there are no mature technologies in the world. Therefore, we proposed a comprehensive development process, including the following measures: (1) Vertical injection-production well pattern enhanced by multi-layer fracturing and hot water injection by seawater source heat pump. (2) An advanced multi-layer hydraulic fracturing technique incorporating cold fracturing fluid, low-temperature consolidation proppant, multi-stage sliding sleeve packer, and a chemical diverting agent. (3) A series of sand control measures including hydraulic fracturing, consolidation proppant, and stand-alone screen. (4) Several rounds of hot water injection-soaking-production (huff-n-puff) on injection wells, and finally continuous injection-production, with depressurization. Then, we built a gas hydrate decomposition rate model to simulate this process. The results show that hot water injection combined with multi-layer hydraulic fracturing can significantly improve the gas hydrate dissociation rate compared with the schemes without hot water injection or fracturing. Combining hot water injection by seawater source heat pump, multi-layer horizontal fractures by advanced hydraulic fracturing technique, and a set of sand control techniques, can efficiently control sand while producing gas hydrate. [ABSTRACT FROM AUTHOR]

Copyright of China Petroleum Machinery is the property of China Petroleum Machinery Editorial Department and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

During the drilling process of horizontal wells in offshore oil fields, when encountering highly clayey shale or sandy shale sections, a common practice is to use a combination of blank pipes and screen pipes in the completion column to isolate high clay content layers. This helps prevent significant clay blockage in the screen pipes or wellbore, thereby reducing production loss. However, when blank pipes cannot effectively isolate clayey or sandy shale sections, the migration of clay content can lead to screen pipe blockage, adversely affecting production capacity. Given the current lack of evaluation methods for the impact of combined blank and screen pipe completion columns on production capacity, an experiment was designed to evaluate the skin factor of the completion column with a combination of blank and screen pipes. Through the calculation of the skin factor, the variation patterns of the skin factor for completion columns with blank and screen pipes under different conditions were obtained. These findings were then applied to a production evaluation. The research results revealed the following: (1) As the proportion of blind pipes increases, the skin factor of the combination of blind pipes and screen pipes in the completion tubing also increases. Excessive blind pipe ratios reduce production capacity. (2) In cases where the annular space is not completely filled, the influence of the blind pipe proportion on production capacity can be negligible. However, when the annular space is 100% filled, a higher proportion of blind pipes and silt content results in a larger skin factor, which leads to reduced production. In the application of the XH horizontal well case study, using the calculated model for the skin factor of the combination of blind pipes and screen pipes in the completion tubing established in this paper, it was determined that when the annular space was not completely blocked and 20 m of blind pipes were not placed in the designated position, the impact on the production index was 0.73%. However, when the blind pipes were not placed in the designated position for 100 m, the impact on the production index reached 1.47%. The method developed in this paper provides theoretical guidance for the optimization of completion tubing in mudstone and sandy mudstone sections and for production evaluation. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Radial well filled with phase change material has been proposed as a novel sand control method for hydrate exploitation. In order to reveal the sand control mechanism, CFD-DEM coupling method is applied to simulate the migration, settlement, and blockage processes of sand particles in the radial well. The obtained results indicate that three scenarios have been recognized for sand particles passing through sand control medium, based on the diameter ratio of sand control medium to sand particle (Dd): fully passing (Dd = 8.75-22.5), partially passing and partially blocked (Dd = 3.18-5.63), and completely blocked (Dd = 2.18-3.21). After being captured by the sand control medium, sand particles can block pores, which increases fluid flow resistance and causes a certain pressure difference in the radial well. The pressure in the radial well should be lower than the hydrate phase equilibrium pressure during sand control design, for the purpose of promoting hydrate decomposition, and sand capture. The length of the radial well should be optimized based on the reservoir pore pressure, production pressure difference, bottom hole pressure, and the pressure gradient in the radial well. It should be noticed that the sand control medium leads to a decrease in permeability after sand particles captured. Even the permeability is reduced to several hundred millidarcy, it is still sufficient to ensure the effective flow of gas and water after hydrate decomposition. Increasing fluid velocity reduces the blocking capacity of the sand control medium, mainly because of deterioration in bridging between sand particles. [ABSTRACT FROM AUTHOR]

The installation of sand screens in open-hole completions in the wellbore is crucial for managing sand production. The main reason for using standalone screens in open-hole completions is their relatively reduced operational complexity compared to other sand control technologies. However, directly applying the screen to the bottom of the hole can lead to an incorrect screen type selection, resulting in an unreliable sand control method. To address this issue, a sand retention test is conducted to evaluate the performance of a standalone screen before field installation. Nevertheless, current sand retention test setups encounter several challenges. These include difficulties in identifying minimum retention requirements, interpreting results in the context of field conditions, and replicating field-specific parameters. The existing sand retention test introduces uncertainties, such as inaccurately replicating field requirements, inconsistent selection of wetting fluids, flow rates, and channel formation, leading to variations in the choice of the optimal screen using this test. In response to these challenges, this study aims to review the sand retention test and propose an improved sand retention method to overcome these problems. The focus of this article is to provide an in-depth analysis of previous sand retention test setups, their contributions to characterizing sand screens, and the parameters utilized in determining test outcomes. Additionally, this review outlines a procedure to investigate the impact of different particle sizes on screen erosion. Key findings emphasize the importance of using high-quality materials, proper screen design to resist damage and erosion, achieving acceptable natural packing behind the screen, and considering factors such as geology, wellbore conditions, and installation techniques. The analysis reveals that a high quantity of finer and poorly sorted sand increases sand production. The study recommends performing a sand pack test closer to reservoir conditions for better evaluation. Premium sand screens demonstrate the highest retention capacity, followed by metal mesh and wire-wrapped screens. Additionally, geotextiles show potential for enhancing sand retention, and screen design affects erosion resistance and service life. [ABSTRACT FROM AUTHOR]

Abstract The installation of sand screens in open-hole completions in the wellbore is crucial for managing sand production. The main reason for using standalone screens in open-hole completions is their relatively reduced operational complexity compared to other sand control technologies. However, directly applying the screen to the bottom of the hole can lead to an incorrect screen type selection, resulting in an unreliable sand control method. To address this issue, a sand retention test is conducted to evaluate the performance of a standalone screen before field installation. Nevertheless, current sand retention test setups encounter several challenges. These include difficulties in identifying minimum retention requirements, interpreting results in the context of field conditions, and replicating field-specific parameters. The existing sand retention test introduces uncertainties, such as inaccurately replicating field requirements, inconsistent selection of wetting fluids, flow rates, and channel formation, leading to variations in the choice of the optimal screen using this test. In response to these challenges, this study aims to review the sand retention test and propose an improved sand retention method to overcome these problems. The focus of this article is to provide an in-depth analysis of previous sand retention test setups, their contributions to characterizing sand screens, and the parameters utilized in determining test outcomes. Additionally, this review outlines a procedure to investigate the impact of different particle sizes on screen erosion. Key findings emphasize the importance of using high-quality materials, proper screen design to resist damage and erosion, achieving acceptable natural packing behind the screen, and considering factors such as geology, wellbore conditions, and installation techniques. The analysis reveals that a high quantity of finer and poorly sorted sand increases sand production. The study recommends performing a sand pack test closer to reservoir conditions for better evaluation. Premium sand screens demonstrate the highest retention capacity, followed by metal mesh and wire-wrapped screens. Additionally, geotextiles show potential for enhancing sand retention, and screen design affects erosion resistance and service life.

Low-coverage line-belt-pattern protective forests offer significant advantages in terms of wind and sand control measures. It is important to study the windbreak effectiveness of sand-fixing forests with different spacing for the construction and optimization of plant shelterbelt configurations. The effect of plant spacing on the flow field around a row of trees was investigated using the k-ε turbulence model coupled with the porous media model. In order to accurately simplify the complex and stochastic plant constitutive features, we simplify the plant canopy to a circular platform geometry, which introduces a porous media model, and the plant trunk is simulated as a solid cylinder. The simulation results show that windbreaks only affect wind profiles up to 1.25-times the height of the tree; on the leeward side of the canopy, large-spaced shelterbelts provide greater protection in the near-wake zone, while small-spaced shelterbelts are more effective at reducing velocity in the re-equilibration zone. The flow field recovery properties of the trunk and canopy indicate that the canopy wake zone is longer. In this study, we also quantitatively analyze the relationship between average wind protection effectiveness as a function of plant spacing and streamwise distance from the leeward side of the canopy, and the given parameterized scheme shows a power exponential relationship between wind protection effectiveness and plant spacing and a logarithmic relationship with streamwise distance. This scheme can provide a predictive assessment of the effects during the implementation of the plant shelterbelt. [ABSTRACT FROM AUTHOR]

During the development of natural gas hydrates, it is important to ensure the stability of the reservoir. The hydrate reservoirs in the South China Sea are clayey silt sediments, which are prone to sand production and collapse during hydrate dissociation. This study innovatively proposes the idea of consolidation-acidizing for NGH reservoir modification. Based on the core parameters of well A drilling in the Shenhu Sea area of the South China Sea, NGH sediment skeleton samples were artificially prepared. Core sensitivity testing indicates that the NGH reservoir has the potential for acidizing modification. After using tetraethyl orthosilicate to solidify the sample, it was found that Young's modulus of the sample increased by 58.8%, and the compressive strength increased by 54.78%. Although the porosity decreased by 39.33%, the pores were not completely blocked. After the acidizing experiment, the permeability of the consolidated sample was 2.88 mD, and the porosity increased by 10.63%; The permeability of the unconsolidated sample was 1.86 mD, and the porosity decreased by 10.73%. The CT scan images also showed that the pores of the sample after consolidation-acidizing developed uniformly without significant deformation; The unconsolidated sample undergoes severe deformation and sand production after acidizing. This study demonstrates that the consolidation-acidizing modification method is feasible in clayey silt hydrate reservoirs. [ABSTRACT FROM AUTHOR]

Coalbed methane well sand (pulverized coal) problem restricts the production life of coalbed methane well, resulting in high maintenance costs, reduce productivity, and because of the large contact area between thin interbed coal seam and surrounding rock, the problem of sand production (pulverized coal) is prominent. In the Surat Basin of Australia, the coal seam cementation is loose and the coal/mud/sandstone interlayer is complex. In the statistical wells, 100% of the production wells have different degrees of sand production problems, and 33.5% of which have serious sand production, frequent workover operations, and high production costs. Based on the systematic analysis of the reservoir characteristics, sand production characteristics and production rules in Surat Basin, the comprehensive sand discharge prevention technology of “expansion packer + blind tube” and “screw pump + slurry rotor + automatic shunt valve + drilling through casing shoes” is adopted according to the research on the particle settlement law, combined with the prediction of sand production level and the optimization of sand control technology. The problem of sand production in coal measure strata in Surat Basin has been solved in stages. The field application results show that the average continuous production time of a single well increases from 275 days to nearly 400 days, and the workover frequency is reduced by nearly 50%.

Static Poisson's ratio (νs) is crucial for determining geomechanical properties in petroleum applications, namely sand production. Some models have been used to predict νs; however, the published models were limited to specific data ranges with an average absolute percentage relative error (AAPRE) of more than 10%. The published gated recurrent unit (GRU) models do not consider trend analysis to show physical behaviors. In this study, we aim to develop a GRU model using trend analysis and three inputs for predicting νs based on a broad range of data, νs (value of 0.1627–0.4492), bulk formation density (RHOB) (0.315–2.994 g/mL), compressional time (DTc) (44.43–186.9 μs/ft), and shear time (DTs) (72.9–341.2 μs/ft). The GRU model was evaluated using different approaches, including statistical error analyses. The GRU model showed the proper trends, and the model data ranges were wider than previous ones. The GRU model has the largest correlation coefficient (R) of 0.967 and the lowest AAPRE, average percent relative error (APRE), root mean square error (RMSE), and standard deviation (SD) of 3.228%, −1.054%, 4.389, and 0.013, respectively, compared to other models. The GRU model has a high accuracy for the different datasets: training, validation, testing, and the whole datasets with R and AAPRE values were 0.981 and 2.601%, 0.966 and 3.274%, 0.967 and 3.228%, and 0.977 and 2.861%, respectively. The group error analyses of all inputs show that the GRU model has less than 5% AAPRE for all input ranges, which is superior to other models that have different AAPRE values of more than 10% at various ranges of inputs.

As an independent sand control unit or a common protective shell of a high-quality screen, the punching screen is the outermost sand retaining unit of the sand control pipe which is used in geothermal well or oil and gas well. However, most screens only consider the influence of the internal sand retaining medium parameters in the sand control performance design while ignoring the influence of the plugging of the punching screen on the overall sand retaining performance of the screen. To explore the clogging mechanism of the punching screen, this paper established the clogging mechanism calculation model of a single punching screen sand control unit by using the computational fluid mechanics-discrete element method (CFD-DEM) combined method. According to the combined motion of particles and fluids, the influence of the internal flow state on particle motion and accumulation was analyzed. The results showed that (1) the clogging process of the punching sand control unit is divided into three stages: initial clogging, aggravation of clogging and stability of clogging. In the initial stage of blockage, coarse particles form a loose bridge structure, and blockage often occurs preferentially at the streamline gathering place below chamfering inside the sand control unit. In the stage of blockage intensification, the particle mass develops into a relatively complete sand bridge, which develops from both ends of the opening to the center of the opening. In the stable plugging stage, the sand deposits show a "fan shape" and form a "Vshaped" gully inside the punching slot element. (2) Under a certain reservoir particle-size distribution, The slit length and opening height have a large influence on the permeability and blockage rate, while the slit width size has little influence on the permeability and blockage rate. The microscopic clogging mechanism and its law of the punching screen prevention unit are proposed in this study, which has some field guidance significance for the design of punching screen and sand prevention selection. [ABSTRACT FROM AUTHOR]

Sand production is one of the main obstacles restricting gas extraction efficiency and safety from marine natural gas hydrate (NGH) reservoirs. Particle migration within the NGH reservoir dominates sand production behaviors, while their relationships were rarely reported, severely constrains quantitative evaluation of sand production risks. This paper reports the optical observations of solid particle migration and production from micrometer to mesoscopic scales conditioned to gravel packing during depressurization-induced NGH dissociation for the first time. Theoretical evolutionary modes of sand migration are established based on experimental observations, and its implications on field NGH are comprehensively discussed. Five particle migration regimes of local borehole failure, continuous collapse, wormhole expansion, extensive slow deformation, and pore-wall fluidization are proved to occur during depressurization. The types of particle migration regimes and their transmission modes during depressurization are predominantly determined by initial hydrate saturation. In contrast, the depressurization mainly dominates the transmission rate of the particle migration regimes. Furthermore, both the cumulative mass and the medium grain size of the produced sand decrease linearly with increasing initial methane hydrate (MH) saturation. Discontinuous gas bubble emission, expansion, and explosion during MH dissociation delay sand migration into the wellbore. At the same time, continuous water flow is a requirement for sand production during hydrate dissociation by depressurization. The experiments enlighten us that a constitutive model that can illustrate visible particle migration regimes and their transmission modes is urgently needed to bridge numerical simulation and field applications. Optimizing wellbore layout positions or special reservoir treatment shall be important for mitigating sand production tendency during NGH exploitation. [ABSTRACT FROM AUTHOR]

In recent years, Baarin Right Banner has accumulated rich experience in sand control, and has made remarkable achievements in ecological restoration, income increase for farmers and herdsmen, and industrial restructuring. However, there are still some problems such as the increasing difficulty of sustainable governance, the arduous task of consolidating achievements, and the lack of perfection of relevant policy mechanisms, it is recommended that the management of Horqin Sandy Land should be further strengthened through rational planning and layout, systematic management measures, transformation and upgrading of industrial mode of production, stimulating the enthusiasm of farmers and herdsmen, and strengthening law enforcement and management, we will continue to promote rural revitalization. [ABSTRACT FROM AUTHOR]

Copyright of Materials Protection (0351-9465) is the property of Engineers Society for Corrosion Republic of Serbia, Belgrade and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Wire-wrapped screens have been established as one of the primary sand control devices in Steam-Assisted Gravity Drainage (SAGD) wells due to the high open-to-flow area and superior plugging attributes. However, their design is still a point of interest for thermal operations. Generally, existing approaches rely on one or more particular points of reservoir sands’ particle size distribution (PSD) and rules of thumb inferred from other devices like the slotted liners. This study used Sand Retention Testing (SRT) to analyze the performance of WWS under various testing conditions, which were neglected in the current design criteria. The experimental investigation leads to a set of graphical design criteria that provide an optimum aperture size window. The results show that the sand retention performance of WWS is highly dependent on the flow velocities of the wetting phase. Moreover, the testing showed satisfactory plugging performance of WWS even with narrow aperture sizes, proving a superior performance for low-quality oil sands.

To further understand the characteristics of clay and sand production (hereafter collectively referred to as sand production) and to provide optimization designs of sand control schemes are critical for gas production from clayey silt natural gas hydrate reservoirs in the South China Sea. Thus, gas-water-sand production behavoirs and coupling reservoir subsidence characteristics before, during, and after hydrate dissociation of the clayey silt hydrate reservoirs with different clay contents (5%, 10%, 15%, 20%, 25%, and 30%) have been studied through a self-developed experimental system. The results show that with the increase of clay content, the total mass of sand production first increases and then decreases, and it reaches maximum when the clayey content is 20%. The sand production is the lowest before hydrate dissociation and increases significantly during hydrate dissociation, which mainly occurs in the high-speed gas and water production stage at the beginning of hydrate dissociation. After hydrate dissociation, the sand production decreases significantly. During the whole depressurization process, the clay and free sand particles generally move to the sand outlet due to the fluid driving force and overlying stress extrusion. However, for conditions of high clay contents, those particles fail to pass through the sand control screen and gradually accumulate and block the screen by forming a mud cake, which greatly reduce the permeability of the screen and limite sand production as well as gas and water production. Our research lays a foundation for sand production prediction and sand control scheme selection during gas recovery from clayey silty hydrate reservoirs that greatly need to consider a balance between sand control and gas productivity.

Many reservoirs comprised of relatively young sediments are so poorly consolidated that sand will be produced along with the reservoir fluids unless the rate is restricted significantly. The mathematical modelling of the flow of the sanded well uses the continuity equation written in cylindrical coordinates, Darcy's law admitting its availability and the solutions of these equations obtained for the boundary conditions in the case of a crude oil well that produces sand floods. In this article we have created a numerical model based on the variation of fluid flow from the productive layer, depending on the pressure drop between the productive layer and the wellbore, as well as the permeability of the layer. As a function of the flows extracted from the well, we rewrote the flow variation equations as polynomial relations of order 5, the error being a maximum of 0.04%. After determining the flow through the two relationships and confronting the reality in the field, the article confirms the type of flow through sand.

Marine natural gas hydrate (NGH) can mainly be found in argillaceous fine-silt reservoirs, and is characterized by weak consolidation and low permeability. Sand production is likely to occur during the NGH production process, and fine-silt particles can easily plug the sand-control media. In view of this, experiments were conducted to assess the influence of the formation sand on the sand retention media in gravel-packed layers under gas–water mixed flow, and the plugging process was analyzed. The results show that following conclusions. (1) The quartz-sand- and ceramic-particle-packed layers show the same plugging trend, and an identical plugging law. The process can be divided into three stages: the beginning, intensified, and balanced stages of plugging. (2) The liquid discharge is a key factor influencing the plugging of gravel-packed layers during NGH exploitation by depressurization. As the discharge increases, plugging occurs in all quartz-sand packing schemes, while the ceramic-particle packing scheme still yields a high gas-flow rate. Therefore, quartz sand is not recommended as the packing medium during NGH exploitation, and the grain-size range of ceramic particles should be further optimized. (3) Due to the high mud content of NGH reservoirs, a mud cake is likely to form on the surface of the packing media, which intensifies the bridge plugging of the packed layer. These experiment results provide an important reference for the formulation and selection of sand-control schemes. [ABSTRACT FROM AUTHOR]

Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Wire-wrapped screens have been established as one of the primary sand control devices in Steam-Assisted Gravity Drainage (SAGD) wells due to the high open-to-flow area and superior plugging attributes. However, their design is still a point of interest for thermal operations. Generally, existing approaches rely on one or more particular points of reservoir sands' particle size distribution (PSD) and rules of thumb inferred from other devices like the slotted liners. This study used Sand Retention Testing (SRT) to analyze the performance of WWS under various testing conditions, which were neglected in the current design criteria. The experimental investigation leads to a set of graphical design criteria that provide an optimum aperture size window. The results show that the sand retention performance of WWS is highly dependent on the flow velocities of the wetting phase. Moreover, the testing showed satisfactory plugging performance of WWS even with narrow aperture sizes, proving a superior performance for low-quality oil sands. [ABSTRACT FROM AUTHOR]

Sand production significantly influences the safety and stability of gas hydrate exploitation in reservoirs with high mud content. Gravel packing is an effective method for sand control. The median grain size ratio (D50/d50) values and fine particle content of gravel pack are important factors in sand control during natural gas hydrate exploitation. This paper focuses on the sand blocking effect and permeability characteristics of different grades of gravel. The sand retention test was carried out on four samples with different ratios. The optimal D50/d50value and fine particle content for gas hydrate production were obtained. A laser particle size analyzer and geotechnical test found the reservoir and gravel layer pore structure change. The results show that the optimal GSR was 24.5, and the optimal fine particle content was about 38%. The permeability decline of the gravel layer occurs in the early stage of production, and the fine particles in the gravel will slow down the degree of seepage damage. For gravel with the same particle size range and different median particle sizes, it has little effect on sand control accuracy but mainly on permeability. The research in this paper can provide a reference for selecting sand control gravel for natural gas exploitation in marine areas.

In this study, the performance of preformed dual crosslinked nanocomposite hydrogels (PNCH) consisting of acrylamide, 2-acrylamide-2-methylpropane sulfonic acid, maleic acid, and acrylic acid in sand control was investigated. Also, the effects of three nanoparticles (NPs) of iron (PNCH1), silicon (PNCH2), and bentonite (PNCH3) on the PNCH structure were studied. The morphology, equilibrium swelling ratio (ESR), rheology, thermal strength, zeta potential, and compressive strength were experimentally analyzed. According to the XRD results, the NPs were completely dispersed in all three samples. The results of SEM and EDS tests confirmed the presence of NPs within the PNCHs with a dense, homogeneous, and porous structure. The results of the ESR at distilled and formation water at ambient temperature for PNCHs (1), (2), and (3) were (13.9,4.55), (15.45, 6.35), and (12.9, 4.8), also at reservoir temperatures ESR results were reported (78, 17.5), (89, 13), and (70,12.9) respectively. From the TGA results, structure destruction of PNCHs starts at 222, 225, and 202 °C respectively so the addition of 1 wt% of NPs increased the structure destruction from nearly 80 °C to more than 200 °C. Based on the results of the strain sweep test, structures of PNCHs can cause viscoelastic behavior with the maximum elastic modulus of 29,000, 8430, and 10,800, and critical strain of (10%, 19.3%, and 10.8%) respectively. The loop test results confirmed the time-dependent viscoelastic properties of thixotropic in all structures. Finally, in compressive strength test revealed that adding 0.5 pore volume of 1 wt% of PNCH into the sandpack increased its strength by 980%.

Sand production is a critical issue in petroleum wells. The critical total drawdown (CTD) is an essential indicator of the onset of sand production. Although some models are available for CTD prediction, most of them are proven to lack accuracy or use commercial software. Furthermore, the previous correlations have not studied the trend analysis to verify the correct relationships between the parameters. Therefore, this study aims to build accurate and robust models for predicting CTD using response surface methodology (RSM) and support vector machine (SVM). The RSM is utilized to obtain the equation without using any software. The SVM model is an alternative method to predict the CTD with higher accuracy. This study used 23 datasets to develop the proposed models. The CTD is a strong function of the total vertical depth, cohesive strength, effective overburden vertical stress, and transit time with correlation coefficients (R) of 0.968, 0.963, 0.918, and −0.813. Different statistical methods, that is, analysis of variance (ANOVA), F‐statistics test, fit statistics, and diagnostics plots, have shown that the RSM correlation has high accuracy and is more robust than correlations reported in the literature. Moreover, trend analysis has proven that the proposed models ideally follow the correct trend. The RSM correlation decreased the average absolute percent relative error (AAPRE) by 12.7% compared to all published correlations' AAPRE of 22.6%–30.4%. The SVM model has shown the lowest AAPRE of 6.1%, with the highest R of 0.995. The effects of all independent variables on the CTD are displayed in three‐dimensional plots and showed significant interactions. [ABSTRACT FROM AUTHOR]

Due to its long lifespan and high sand-removal efficiency, gravel packing is one of the most applied sand control methods during the recovery of reservoirs with sanding problems. The blockage and retention of injected sand in a gravel pack is a complex process affected by multiple mechanisms. The majority of existing studies based on the phenomenological deep bed filtration (DBF) theory focused on the gravel pack's overall permeability damage and failed to obtain the inner-pore particle distribution pattern. In this work, experiments and simulations were carried out to reveal the particle distribution in a gravel pack during flooding. In particular, through real-time monitoring of particle migration, the penetration depth and distribution pattern of invaded particles with different gravel-sand particle ratios, fluid viscosities and injection rates could be determined. By simplifying each unit bed element (UBE) into a pore-throat structure with four tunnels (two horizontals for discharge and two verticals for sedimentation), a new network simulation method, which combines deep bed filtration with a particle trajectory model, was implemented. Cross comparison of experimental and numerical results demonstrates the validity and accuracy of the model. [ABSTRACT FROM AUTHOR]

There are many technologies to implement sand control in sand-prone wells, drilled in either weakly or nonconsolidated sandstones. Technologies that are used to prevent sanding can be divided into the following groups: screens (wire-wrapped screens, slotted liners, premium screens, and mesh screens), gravel packs, chemical consolidation, and technological ways (oriented perforation and bottomhole pressure limitation) of sanding prevention. Each particular technology in these groups has their own design and construction features. Today, slotted liners are the most well-studied technology in terms of design, however, this type of sand control screen is not always accessible, and some companies tend towards using wire-wrapped screens over slotted liners. This paper aims to study the design criteria of wire-wrapped screens and provides new data regarding the way in which wire design affects the sanding process. Wires with triangular (wedge), trapezoidal, and drop-shaped profiles were tested using prepack sand retention test methodology to measure the possible impact of wire profile on sand retention capabilities and other parameters of the sand control screen. It was concluded that a trapezoidal profile of wire has shown the best result both in terms of sand production (small amount of suspended particles in the effluent) and in particle size distribution in the effluent, that is, they are the smallest compared to other wire profiles. As for retained permeability, in the current series of experiments, high sand retention did not affect retained permeability, although it can be speculated that this is mostly due to the relatively high particle size distribution of the reservoir. [ABSTRACT FROM AUTHOR]

Fine sand production is a crucial concern of the Rudrasagar oilfield of Upper Assam. Petroliferous basin as it develops numerous issues related to oil and gas production. Sand production from oil wells has a negative impact on the economy of oil production since it can harm both surface and subsurface equipment as well as impair the well's productivity. Since the conventional gravel pack cannot hold the fines at the formation of the Rudrasagar oilfield, sand consolidation by introducing suitable chemicals may prove as an efficient technique to control sand production and thereby maintain the permeability needed for the fluid to flow. Keeping this view in mind, an attempt has been in the present study to formulate a novel mixture of chemicals that may efficiently consolidate the loose sand particles under the reservoir conditions of the Rudrasagar oilfield. The experiment shows that when epoxy resin is mixed with consolidating agents while maintaining relatively high porosity and permeability, the uniaxial compressive strength (UCS) of the studied sandstone is greatly improved. The newly developed chemical solution of 10% epoxy resin, 6% bitumen, and 1% bentonite is best suited to provide UCS value up to 1134 psi to the studied sand grains, with retaining permeability up to 75% with absolute permeability of 1218 mD. Hence, this solution can be recommended commercially in the sand consolidation treatments of the Rudrasagar oilfield. [ABSTRACT FROM AUTHOR]

In the exploitation of mud hydrate reservoirs, mud films are formed in unconsolidated mud reservoirs under the action of soil particle migration, which changes the permeability and sand retention effect. This can affect the failure mode and gas productivity of the reservoir. A self-developed experimental test system was used to investigate the mud film formation process and failure characteristics in mud reservoirs under gravel packing sand retention conditions at tangential flow rates of 0.424, 0.849, 1.273, 1.697, and 2.122 × 10−3 cm/s. The results indicated that (1) the flow velocity affects the mud film formation rate and (2) the flow velocity notably influences seepage flow. When the flow velocity is higher than 1.697 × 10−3 cm/s, the mud film and sand control layer suddenly fail, and the flow process changes from seepage to fissure flow. (3) Mud film formation results from soil particle migration, and mud films can control sand retention. (4) The mechanism of mud film formation is that water flow can lead to reservoir compression deformation under pressure. Water flow can result in seepage dominating in the reservoir. The above analysis results could provide a reference for groundwater injection and hydrate exploitation. [ABSTRACT FROM AUTHOR]

Many reservoirs comprised of relatively young sediments are so poorly consolidated that sand will be produced along with the reservoir fluids unless the rate is restricted significantly. The mathematical modelling of the flow of the sanded well uses the continuity equation written in cylindrical coordinates, Darcy's law admitting its availability and the solutions of these equations obtained for the boundary conditions in the case of a crude oil well that produces sand floods. In this article we have created a numerical model based on the variation of fluid flow from the productive layer, depending on the pressure drop between the productive layer and the wellbore, as well as the permeability of the layer. As a function of the flows extracted from the well, we rewrote the flow variation equations as polynomial relations of order 5, the error being a maximum of 0.04%. After determining the flow through the two relationships and confronting the reality in the field, the article confirms the type of flow through sand. [ABSTRACT FROM AUTHOR]

Sand production is one of the serious challenges in the petroleum industries all around the world which could damage the productivity of wells. In this regard, laboratory methods are being conducted to control sand production before using sand controlling systems or conventional methods to control sand production in wells or reservoirs. Particle size distribution (PSD) is essential to perform laboratory experiments needs. PSD is determined by screening and laser granulation analysis or wetting sieve device. In this paper, the PSD of sand particles from core samples in 18 wells has been analyzed. Selected wells and their PSD of cores represent a wide range of wells with sand production problems in two important oil reservoirs in southwestern Iran. The sand PSD in these samples has been analyzed statistically. Among the 18 samples discussed, 4 had moderately well-sorting, 5 moderately sorting, 7 poorly sorting, and 2 very poorly sorting. The average value of the uniformity coefficient of sand particles in the samples was equal to 2.568, indicating the uniformity of the analyzed sands. The 0.614 to 1.2495 mm was determined as a minimum and maximum size to estimate the size of the slot width for designing coupons of the sand retention teste (SRT)s apparatus. The results of this study can be used in the design and selection of sand production control devices. [ABSTRACT FROM AUTHOR]

Abstract As the natural gas hydrate (NGH) resources show a bright future, more and more commercial and technical focuses have been devoted to this area. The low productivity, the sanding problem, and the poor economic performance are vital problems hindering the long‐term commercial exploration and development of NGS sediments. Among all these problems, the sanding problem can aggravate the low productivity and the poor economic efficiency problems. Therefore, it is necessary to investigate and tackle the sanding problem for the safe, long‐term, and large‐scale commercial development of offshore NGH resources. The sanding problem of the NGH sediment is highly related to the mechanical behavior of sediment. The main influencing factors are discussed, which are hydrate saturation, effective confining pressure, sand content, hydrate distribution, and multiple‐physical fields. This article summarizes the current research achievements systematically to determine how these factors affect sand production in NGH sediments. Besides the macrolevel about mechanical behaviors of NGH sediment, the sand motion modeling is also included in this review. The source of sand production is the free‐moving sand which comes from formation deformation. The review compares most commonly used yield criteria and then recommends a proper one for NGH sediments. The paper subsequently discusses the common investigation methods for the sanding problem in this area, including numerical simulation and experiments. The design and effect of sand control techniques have also been reviewed and discussed. According to the review results, the paper concludes the current research drawbacks and generates suggestions for future research. The novel methods of sand control investigation are machine learning and optimization methods.

This work focuses on the assessment of the effect of well completion types on gas productivity in subsea gas hydrate reservoirs of class 1G type where the gas hydrates have decomposed into gas and water. Three types of vertical well completions are considered: frac-packed well with vertical hydraulic fracture; frac-packed well with horizontal hydraulic fracture, and a cased-hole gravel-packed well. Sensitivity analysis was conducted with analytical well inflow models to determine factors that affect the gas well productivity. The results of the analyses indicated that proppant mass pumped during fracture treatment slightly improves well productivity for frac-packed natural gas hydrate wells. Well productivity increases nonlinearly with fracture productivity up to a threshold value of 50,000 md for frac-packed well with horizontal fracture, above which further increase in fracture conductivity would create no benefit. With a proppant mass of 50,000 Ibm and a corresponding proppant volume of 504 ft3, commercial gas production rates of 14.9 MMscf/d, 5.621 MMscf/d, and 11.35 MMscf/d are possible for frac-packed well with vertical fracture, frac-packed well with horizontal fracture, and cased-hole gravel-packed well, respectively. Because hydraulic fracture orientation depends on the in-situ formation stress, whether a well should be hydraulic-fractured or not depends on in-situ formation stress.

Natural gas hydrate is a promising substitute energy resource for the future. Currently, the inefficient sand control technology impedes the commercialization of Natural gas hydrate. The main challenge lies in breaking the consolidation of Natural gas hydrate and sands, and then separating micrometer-sized sands from the drilling fluid. In this paper, we present a technology based on hydroscyclone that effectively breaks the consolidations and removes sand. We used polypropylene powders and silica sands as substitutes for the hydrates and sands, and we added cement to replicate the consolidation. Inside the hydrocyclone, the material particles receive a strong shear force from the 3-dimension rotating swirling flow field generated by the device, as well as a centrifugal force produced by their own rotation and revolution. With the high-speed camera, we observed the effect of these forces breaking the consolidation and separating sands. It was further noted that the proportion of residual polypropylene powders in the recovered materials were between 0.46% and 1.05% after the materials were processed by the hydrocyclone. The low residual content of polypropylene powders demonstrated the success of hydrocyclone technology in breaking the consolidation and effectively addressing the problem of sand control in the extraction of Natural gas hydrate and sands.

The consequences of sandstone reservoir rock failure may lead to sand production. This phenomenon can have negative impact on lifting cost and economic of any field development. Metal erosion due to sanding can lead to loss of integrity and hydrocarbon leakage. Poor decision on the type of completion can risk the viability of the field. To facilitate best sand management over the life of a field and to maintain economical productivity, accurate prediction of sand production volume/rates is needed to increase both productivity and the ultimate recovery of the hydrocarbon while keeping the operating cost low. This paper summarizes the sand production modeling for onset and volume of sand namely technology that required to improve understanding on sand production and mitigation. Three main questions will be answered, why industry needs to worry about sand production, what are the available technologies to predict sanding volume/rates finally, how the current technologies can be improved to estimate sand production volume/rates.