Petroleum Science >2015,??Issue 4:??636-650 DOI: https://doi.org/10.1007/s12182-015-0049-2
Experimental investigation of shale imbibition capacityand the factors influencing loss of hydraulic fracturing fluids Open?Access
文章信息
State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China;State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China;State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China;State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China;State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China;State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China;State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China
文章摘要
fluids into the shale matrix is considered to be the
main mechanism responsible for the high volume of water
loss during the flowback period. Understanding the matrix
imbibition capacity and rate helps to determine the fracturing
fluid volume, optimize the flowback design, and to
analyze the influences on the production of shale gas.
Imbibition experiments were conducted on shale samples
from the Sichuan Basin, and some tight sandstone samples
from the Ordos Basin. Tight volcanic samples from the
Songliao Basin were also investigated for comparison. The
effects of porosity, clay minerals, surfactants, and KCl
solutions on the matrix imbibition capacity and rate were
systematically investigated. The results show that the
imbibition characteristic of tight rocks can be characterized
by the imbibition curve shape, the imbibition capacity, the
imbibition rate, and the diffusion rate. The driving forces of
water imbibition are the capillary pressure and the clay
absorption force. For the tight rocks with low clay contents,
the imbibition capacity and rate are positively correlated
with the porosity. For tight rocks with high clay content,
the type and content of clay minerals are the most important
factors affecting the imbibition capacity. The imbibed
water volume normalized by the porosity increases with an
increasing total clay content. Smectite and illite/smectite
tend to greatly enhance the water imbibition capacity.
Furthermore, clay-rich tight rocks can imbibe a volume of
water greater than their measured pore volume. The average
ratio of the imbibed water volume to the pore volume
is approximately 1.1 in the Niutitang shale, 1.9 in the
Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the
Yingcheng volcanic rock, and this ratio can be regarded as
a parameter that indicates the influence of clay. In addition,
surfactants can change the imbibition capacity due to
alteration of the capillary pressure and wettability. A 10
wt% KCl solution can inhibit clay absorption to reduce the
imbibition capacity.
關(guān)鍵詞
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Imbibition Shale Fracturing fluid Capillary pressure Clay