Experimental study on the performance of sand control screens for gas wells

Jin, Yan; Chen, Junhai; Chen, Mian; Zhang, Fuxiang; Lu, Yunhu; Ding, Jihui

doi:10.1007/s13202-012-0019-9

Cited by 12 publications

(3 citation statements)

References 5 publications

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“…As the height of the brine drainage pipe is not fixed, a 25 cm height is In the secondary brine drainage experiment, the brine drainage tube goes deep into the bottom of the salt cavern. Under high pressure, the insoluble particles move to the brine drainage pipe, which can easily cause pipeline blockage [38]. Therefore, it is necessary to evaluate the sand production rules of three kinds of sand control methods, namely, screen pipe, gravel pack artificial well wall and chemical sand consolidation.…”

Section: Experimental Schemementioning

confidence: 99%

Study on Secondary Brine Drainage and Sand Control Technology of Salt Cavern Gas Storage

Zhang

et al. 2023

Sustainability

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Geological conditions of salt cavern gas storage in China are characterized by dominantly layered salt layers with a high content of insoluble mudstone. After the water leaching of the salt layer, a large amount of sediment accumulates at the bottom of the gas storage cavity. During the gas injection process, only the clean brine above the sediment can be expelled, leaving a brine layer of 2–5 m and a large amount of brine in the pore space of the sediment. To increase storage capacity, it is urgent to explore the secondary gas injection and brine drainage technology to further expel residual brine in pores of the sediment at the cavern bottom. The sediment is relatively loosely packed and is composed of mudstone particles, which easily migrate and block the brine withdrawal pipe. In this paper, firstly, the mineral composition, particle size and distribution characteristics of the sediment at the bottom of the salt cavern are fully understood by XRD and sieve analysis methods. Then, a lab simulation device suitable for secondary gas injection and brine drainage of a high-salinity salt cavern with a diameter and height of 25 cm was designed and built. A screen sand control experiment, a gravel pack artificial wall sand control experiment and chemical cementing sand were simulated. The effects of gas injection, brine drainage pressure, brine layer height and insoluble particle size on sand production and liquid drainage were studied. The influence factors of brine withdrawal on the sand control in secondary brine drainage were intensively investigated, and finally, the gravel pack artificial wall sand control technology system was recommended. The optimal construction parameters for secondary brine discharge are recommended as follows: Under the condition of gravel packing with the same particle size, the trend of sand content with different artificial wall thicknesses is not obvious, and a 2 cm wall thickness is the best in the overall experiment, corresponding to 28 cm in the field. The larger the particle size of the gravel pack, the better the sand control, and the best gravel size is 10–20 mesh. The injection pressure should be as low as possible.

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Section: Experimental Schemementioning

confidence: 99%

Study on Secondary Brine Drainage and Sand Control Technology of Salt Cavern Gas Storage

Zhang

et al. 2023

Sustainability

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“…This difference has prompted some researchers to explore the use of full-scale testing apparatus. 8,21,[27][28][29] However, conducting a full-scale experiment can be quite costly and time consuming. Consequently, such tests are used less frequently due to these factors.…”

Section: Introductionmentioning

confidence: 99%

“…However, the actual flow near the screen should be radial, creating a discrepancy between testing conditions and real‐world applications. This difference has prompted some researchers to explore the use of full‐scale testing apparatus 8,21,27–29 . However, conducting a full‐scale experiment can be quite costly and time consuming.…”

Section: Introductionmentioning

confidence: 99%

Numerical simulations of sand‐screen performance in unconsolidated prepacked gravel screen

Ma,

Dou,

Deng

et al. 2023

Energy Science & Engineering

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This work addresses the ongoing challenge of optimizing sand control screens, attributed to a limited understanding of screen blocking. A novel one‐way computational fluid dynamics and discrete element method (CFD–DEM) coupling technique is presented to analyze the structural parameters of unconsolidated prepacked gravel screens (PPGS). CFD–DEM involves systematically investigating the width of the punched slot on the outer protective screen, the size of the gravel, and the efficiency of gravel packing to improve the antiblocking capability of unconsolidated PPGS. Results from numerical simulations reveal that under conditions of effective sand control, the amount of sand entering the gravel layer to the bridge (referred to as the sand pass rate) is positively correlated with the antilocking ability (referred to as oil productivity index) for unconsolidated PPGS. The efficiency of gravel packing has the most substantial effect on the antilocking performance of unconsolidated PPGS. The data suggest that appropriately reducing the efficiency of gravel packing can enhance the antilocking capability of unconsolidated PPGS. To design an unconsolidated PPGS with enhanced antilocking capability, the efficiency of gravel packing be determined first. Then, the gravel size is designed based on this efficiency, and the width relative to the gravel size is decided. This contemporary design principle diverges considerably from previous design principles for gravel‐packed sand control screens. Supporting validation experiments agree with simulation outcomes, suggesting the established one‐way CFD–DEM coupling method in this paper is suitable for analyzing the plugging mechanism of unconsolidated PPGS. Thus, the CFD–DEM coupling method improves the design of such screens for improved antiblocking performance.

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Determination of regions prone to sand production and the linkage to fluid flow rates by integrating rock strength parameters and microphotographs in the southern onshore basin, India

Kukshal,

Sharma,

Kalita

et al. 2023

J Petrol Explor Prod Technol

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One of the main challenges for healthy hydrocarbon yields from the production wells is the sand production, and its control assumes significant importance for successful production operations. The prime objective remains to control the sand production without compromising on the fluid flow rates. Sand production is conventionally associated with diverse heterogeneous formations, especially poorly consolidated formations. Scrutinizing fluid flow rates at different orientations of perforations is a valuable analysis in controlling the sand production. This study was conducted to examine the case of sand production in a few development wells from Malleshwaram field of the Krishna Godavari (KG) basin in south India and provide alternatives to arrest this sand production. The influence of oriented perforations on fluid flow rates to minimize sanding tendencies was examined. Sand grain diameter was estimated using the distribution plots of the grain sizes obtained from the photomicrographs, and the average value of the grain size was estimated around 100 μm. The fluid flow model was simulated for actual scenario in the hydrocarbon bearing Nandigama formation using finite element modeling (FEM). Sanding tendencies in these formations were studied at varying depletion rates. Critical draw down pressure (CDDP), which is a function of both critical bottom hole pressure and reservoir pore pressure, for well 1 and well 2 is estimated as 4650 Psi and 3400 Psi, respectively, at 0% depletion. CDDP was used to estimate the onset of sanding, and the flow rate for horizontal perforation was calculated as 0.024548 $${\mathrm{m}}^{3}$$ m 3 /sec. Strength parameters, namely the unconfined compressive strength (UCS) and cohesion, were also investigated in all the wells to decipher the formation strength and a possible linkage to sanding. These results present a completely fresh analysis of the sanding potential and the related parameters responsible for it in these formations. Fluid flow rates for the producing reservoir are studied at different set of oriented and sized perforations. It was observed that a hiked flow rate in horizontal perforations maintains the production in a safe and no-sanding zone. This study provides vital information and a workflow for similar heterogeneous complex formations for designing the well completions, augmenting economic production and reinforcing future reservoir management.

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Experimental study on the performance of sand control screens for gas wells

Cited by 12 publications

References 5 publications

Study on Secondary Brine Drainage and Sand Control Technology of Salt Cavern Gas Storage

Study on Secondary Brine Drainage and Sand Control Technology of Salt Cavern Gas Storage

Numerical simulations of sand‐screen performance in unconsolidated prepacked gravel screen

Determination of regions prone to sand production and the linkage to fluid flow rates by integrating rock strength parameters and microphotographs in the southern onshore basin, India

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