Abstract

This paper presents a detailed case history of hydraulic fracture treatments in tight oil reservoirs in remote onshore locations in China. For cases presented in this study, microseismic mapping and fracture modeling approaches were applied to understand fracture growth behavior. This paper provides a brief summary of reservoir background, but focuses on microseismic mapping as well as fracture modeling analysis. Results from fracture modeling and microseismic mapping were employed to understand post-frac performance.

Introduction

Fracture treatments from two tight oil reservoirs, one mature and the other new, were investigated in this study. The two reservoirs of interest are located in the same region in north central China and are about 190 kilometers apart. The mature reservoir is located in Shaanxi Province, with a reservoir depth (TVD) of 1,180 meters at the middle of all the pay zones. The new reservoir is located in Gansu Province, with a mid-pay reservoir depth (TVD) of 2,120 meters. Both of the reservoirs consist of stacked sand/shale deposits and their net pay ranges roughly from 7 to 23 meters. The reservoirs were varied in quality, with permeabilities ranging from 0.05 mD to 0.3 mD, connate water saturations from 30 to 45%, and porosities from 11 to 16%. The effective reservoir permeability values were estimated from previous well test and production analysis. The specific gravity of the crude oil is about 0.85 or an API gravity of 35 degrees. In the development of these tight oil reservoirs, water injection was implemented as soon as oil production was started, to provide the pressure needed for commercial oil production. For under-pressured reservoirs in the region, it is a common practice to start water injection and to bring the reservoir pressure to a certain level before any oil production is started.

All oil wells in these tight reservoirs in the region require fracture stimulation to achieve commercial production and to improve well productivity. Fracture stimulation is also very common for water injection wells to enhance injectivity. For the two cases presented in this study, a microseismic mapping technique using an advanced downhole seismic system (running fiberoptic wireline and geophones receivers in offset wells) was applied for the first time to understand the fracture growth behavior in this region. Hundreds of fracture treatments have been mapped in North America using the same type of downhole seismic systems, though most of these jobs were performed in tight gas wells[1–4]. The cases investigated in this paper involve three frac jobs in oil reservoirs.

Description of Microseismic Mapping

The method of fracture mapping by measuring the locations of microseisms created during a hydraulic fracture treatment has existed for over 20 years[5]. The formation around the fracture undergoes significant stress increases and large changes in the pore pressure during a fracture treatment. Both of these changes affect the stability of planes of weakness adjacent to the hydraulic fracture and cause them to undergo shear slippage. The shear slippages are similar to earthquakes along faults, but with much lower magnitude. The name "microseism" or "microseismic" is thus often used to describe this phenomenon. Microseisms generated during a hydraulic fracture treatment emit elastic waves at frequencies that generally fall within the acoustic frequency range. These acoustic signals can be detected using appropriate receivers and processed to determine the locations of these microseismic events[1]. Microseisms are detected with multiple receivers deployed on a wireline array in one or more offset wellbores (see Figure 1). With the receivers deployed in several wells, the microseism locations can be triangulated as is done in earthquake detection. In most cases, though, multiple offset wells are not available. With only a single nearby offset observation well, a multi-level vertical array of receivers is used to locate the microseisms. Figure 1 illustrates the procedure of measuring the microseisms with a 5-level receiver array, transferring the data to the surface for subsequent processing to yield a map of the hydraulic fracture geometry and azimuth. Once the microseisms are located, the actual fracture is interpreted within the envelope of microseisms mapped.

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