Comprehensive evaluation of formation damage induced by working fluid loss in fractured tight gas reservoir

Kang, Yili; Xu, Chao; You, Lijun; Yu, Haifeng; Zhang, Benjian

doi:10.1016/j.jngse.2014.03.016

Cited by 82 publications

(27 citation statements)

References 6 publications

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“…For such a type of rock matrix, natural fractures may serve as the primary pathway for hydrocarbon to flow into the hydraulic fractures and then the wellbore. It has been found that formation damage in fractures can be difficult to be cleaned up and detrimental to the production [30,31]. However, for this type of reservoir rocks, it remains unknown that the proportion of permeability damage due to either the drilling fluid or the fracturing fluid and its change with the width of natural fractures.…”

Section: Introductionmentioning

confidence: 99%

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Liang

Yao

et al. 2017

Geofluids

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Drilling and fracturing fluids can interact with reservoir rock and cause formation damage that impedes hydrocarbon production. Tight sandstone reservoir with well-developed natural fractures has a complex pore structure where pores and pore throats have a wide range of diameters; formation damage in such type of reservoir can be complicated and severe. Reservoir rock samples with a wide range of fracture widths are tested through a multistep coreflood platform, where formation damage caused by the drilling and/or fracturing fluid is quantitatively evaluated and systematically studied. To further mitigate this damage, an acidic treating fluid is screened and evaluated using the same coreflood platform. Experimental results indicate that the drilling fluid causes the major damage, and the chosen treating fluid can enhance rock permeability both effectively and efficiently at least at the room temperature with the overburden pressure.

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Section: Introductionmentioning

confidence: 99%

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Liang

Yao

et al. 2017

Geofluids

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“…However, large amount of liquid retain in the formation after flowback [13,48]. Thus, the reservoir permeability was damaged severely, which reduce the effective gas flowing during production [49][50][51][52][53][54]. The same water saturation in tight gas reservoir has more impact on permeability than conventional gas reservoir [55].…”

Section: Introductionmentioning

confidence: 99%

Analyzing Tight Sand Characteristics and Its Influence on Aqueous Phase Removal by Gas Displacement

Meng

Shen

et al. 2019

Geofluids

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Tight sand gas is an important unconventional natural gas. Liquid filtration plays a main role in the formation damage. Flowback rate is closely related to the formation permeability recovery. Usually, the more flowback rate is, the better the permeability recovery is. In order to research the factors that influence the liquid flowback, the tight sand characteristics and gas displacement have been investigated. Some experiments were carried out, including porosity, permeability, XRD, casting thin section, SEM, stress sensitivity, rock expansion, and gas displacement. The results are shown as follows. Taiyuan formation has average high clay content than H8 formation. Illite is the main clay in Taiyuan formation; chlorite is the main clay in H8 formation. From the casting thin section, the rock has strong compression. Taiyuan formation has large pore. However, H8 formation mainly has small cracks. Through the SEM, there are many micro- to nanocracks as well as some pores in these two formations. In some cases, cracks penetrate the clays. From the permeability stress sensitivity, these tight sands have strong stress sensitivity. Permeability decreases quickly with increasing confining pressure. In the rock expansion experiment, the tight sand has less expansion rate compared with shale gas rock and volcanic gas rock. Rock expansion rate has positive relationship with clay content. In the gas displacement experiment, usually the higher the clay content, the lesser the liquid flowback. Some samples have high clay content. However, it has high flowback rate, which may account for good pore connection. Through the above study, the flowback rate has negative relationship with clay content and positive relationship with pore size, pore connection, and displacement pressure. In order to increase tight gas production in the study area, the formation should have high flowback rate and less liquid retention. Therefore, clay expansion preventing additives should be added into the fracturing liquid to reduce the liquid retention. The quick flowback should be implemented after hydraulic fracturing for reducing the interaction between liquid and rock. At the same time, the drawdown pressure should keep in a certain value to reduce stress sensitivity.

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“…Liquid and solid particles penetrate deeply into the reservoir and cause serious damage [2][3][4]. Particle invasion, phase trapping damage, and rock-fluid incompatibility are the main causes of formation damage [5][6][7]. ese problems are prominent in the Central Tarim Basin.…”

Section: Introductionmentioning

confidence: 99%

Laboratory Study on a New Composite Plugging Material with High Bearing Strength and High-Temperature Resistance

Lian

Xiong

et al. 2019

Journal of Chemistry

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The reservoir in the Central Tarim Basin is a typical high-pressure fracture-vuggy carbonate reservoir with high temperatures, which easily leads to drilling fluid losses and the high-temperature carbonate. The conventional lost circulation materials (LCMs) cannot meet the reservoir. To resolve this problem, a rigid particle with high-temperature resistance, high acid solubility, and high rigidity was developed, tested, and evaluated. According to bridge rules of 1/2–2/3 opening degree of formation fracture, the formulation experiments of GZD and other lost circulation materials were conducted and a novel composite lost circulation material (LCM) was completed. Lastly, we investigated the compatibility of LCM and mud in site though compatibility experiment, analyzed the plugging effect of the system for fracture and vuggy by laboratory static lost circulation simulation and evaluation and sand-bed plugging experiments, respectively. The results show that compared with the conventional rigid lost material, the value of high-temperature resistance is more and acid solubility is over 98%. Also, it can work well with other fiber materials (E), variable filling particles (F and G), and superfine filling particles (H) and form a novel plugging material, named MGY-I, whose temperature resistance value is more than 473.15 K, the bearing strength is over than 9 MPa, the mud filtrate invasion depth of sand bed made from coarse particles (10∼20 mesh) is only 3.0 cm within 30 minutes, and the invasion depth is less than 1 cm within 30 minutes when the sand bed is made from 80∼100 mesh. The optimal concentrations of rigid granule, lignin fiber, elastic particle, and superfine calcium carbonate are 8% (A : B : CD = 2 : 1 : 1), 0.5%, 6%, and 1%, respectively. And, the plugging function of “GZD-rigidity bridge and filling, fiber network and deformable filing” is better exerted on the formation fracture with a high loading capacity and a high-temperature resistance.

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Comprehensive evaluation of formation damage induced by working fluid loss in fractured tight gas reservoir

Cited by 82 publications

References 6 publications

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

Analyzing Tight Sand Characteristics and Its Influence on Aqueous Phase Removal by Gas Displacement

Laboratory Study on a New Composite Plugging Material with High Bearing Strength and High-Temperature Resistance

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