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Results
Experimental Study on the Impact of CO2–Brine–Rock Interaction on Rock Properties and Fracture Propagation During Supercritical CO2 Fracturing in Chang-7 Tight Sandstone Formation
Li, S. H. (China University of Petroleum) | Zhang, S. C. (China University of Petroleum) | Zou, Y. S. (China University of Petroleum) | Qi, S. L. (Daqing Oilfield Production Engineering Research Institute) | Ma, X. F. (China University of Petroleum) | Li, N. (China University of Petroleum) | Chen, M. (China University of Petroleum)
ABSTRACT: In view of the physical–chemical properties of CO2, this paper studied the impact of CO2–brine–rock interaction on rock properties and fracture propagation during supercritical CO2 fracturing in Chang-7 tight sandstone. A series of static soaking experiments and true triaxial fracturing experiments were performed to investigate the influence of CO2–brine–rock interaction on rock properties and fracture propagation during supercritical CO2 fracturing. Experimental results showed that calcite, dolomite, K-feldspar, and albite, were variably dissolved during the static soaking experiment. With the increase of reaction time, the number of dissolution pores increased and the pore size enlarged, which caused the enhancement in porosity and permeability (up to one order of magnitude) and the decrement of tensile strength (up to 47%). Compared with slickwater fracturing, supercritical CO2 fracturing reduced the breakdown pressure by 15% and increased the number of fractures. The soaking treatment of the open-hole section of fracturing specimen with CO2-saturated brine reduced the breakdown pressure by 21% and improved the fracture complexity conspicuously in the case of supercritical CO2 fracturing. The obtained results indicate that the physical–chemical properties of CO2 can improve the fracture complexity effectively during supercritical CO2 fracturing in Chang-7 tight sandstone formation.
- Asia > China (0.96)
- Europe (0.68)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.31)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5604/29 > South Arne Field (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- (4 more...)
- Well Drilling > Wellbore Design (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- (3 more...)
Decreasing Water Invasion Into Shale Using Hydrophilic Sulfonated Silica Nanoparticles
Wang, X. (China University of Petroleum) | Chen, M. (China University of Petroleum) | Jin, Y. (China University of Petroleum) | Lu, Y. (China University of Petroleum) | Yang, S. (China University of Petroleum) | Liang, C. (CNPC Offshore Engineering Company Limited)
ABSTRACT ABSTRACT: Water invasion into shale formations while drilling with water-based fluids results in hydration and subsequent wellbore instability. Using nonmodified nanoparticles to seal shale has been proven to be an effective method to reduce shale permeability and decrease water invasion. In this paper, the sealing performance of both nonmodified silica nanoparticles (NPs) and sulfonated nanoparticles (SNPs) is studied by the improved pressure penetration test. The test results indicate that SNPs have better sealing performance than NPs, especially in the direction parallel to the shale bedding planes. The hydrophilic polymers grafted on the surface enable SNPs to disperse better in water so that they can enter and seal shale pores more easily. Consequently, water invasion is prevented, and hydration of shale is inhibited. In addition, SNPs aqueous dispersion shows better sedimentary stability than NPs dispersion at both 25 °C and 85 °C. In conclusion, it is believed that sulfonated nanoparticles have better potential to overcome wellbore instability problems in shale formations. 1. INTRODUCTION Shales account for more than 75% of drilled formations and cause at least 90% of wellbore-stability problems. (Steiger 1992). Shale wellbore instability problems mainly result from two mechanisms. The first one belongs to physical-chemical effect. It is caused by fluid invasion into shale and subsequent hydration and strength reduction (Chenevert, 1970). The second one belongs to mechanics effect. It is caused by the reduction of overbalance force, which is the differential pressure between the drilling fluid column pressure and the pore pressure (Ewy, 2009). Oil-based drilling fluid has been proven to be a good solution to shale wellbore instability, but it is not environment-friendly and not economical (Chenevert, 1970). Both the two shale instability mechanisms can be controlled to some extent by blocking the shale pore to prevent water invasion. Abrams (1977) proposed that the median particle size of the bridging additive should be equal or slightly larger than one-third of the median pore size of the formaiton. Hands et al. (1998) proposed that D90 (90% of the particles are smaller than size x) of the particle-size distribution of the bridging additive should be equal to the pore size of the rock. Al-Bazali el al. (2005) pointed out the average pore throat sizes of shales ranges from 10 to 30nm. Cai et al. (2012) used nonmodified silica nanoparticles to seal Atoka shale and decrease water invasion. Nanoparticles with size ranging from 7 to 15nm and a concentration of 10wt% were shown to be effective at reducing shale permeability and the highest reduction rate reached 99.33%.
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
ABSTRACT: The sub-salt reservoirs of High Temperature and High Pressure (HTHP) are often drilled with Oil-Based Mud (OBM), for the OBM has better rheology and better keeping stability performance than Water-Based Mud (WBM) under HTHP condition. This paper aims to analysis the influence of OBM on salt formation creeping rate, based on the difference on interface tension of OBM. Through the experimental research, it get the relations between salt formation creeping with different exposing time and different interface tensions. An Electron Microscope Scanning Investigation (EMSI) has also been applied for saturated and unsaturated salt samples. Through EMSI, the micro change of salt samples has been testified. The research shows that the interface tension has a great impact on salt creeping. When interface tension increases, the infiltrate length of drilling fluid per unit time increases when quantity of micro-cracks increases, the infiltrate length of drilling fluid per unit time decreases. The experiments in this study were conducted under simulated high formation temperature. The OBM with different interface tension were obtained by adding surfactants into the OBM used in real drilling operations. 1 INTRODUCTION The sub-salt reservoirs are often drilled with OBM, because the WBM's inherent shortage in rheology and in keeping wellbore stability under HTHP condition. On the other hand, the OBM has a better performance in keeping wellbore stability under high temperature. The creeping of salt under WBM has been investigated in variety of studies (Fabre 2006). Some scholars have proposed several different equations for expressing the relationship between stress creeping rate and temperature (Homand 2006). In studies concerned with the micro mechanics of salt creeping, Fredrich (2007) employed statistics analysis on experimental data obtained from the salt rock experiments of Gulf of Mexico. Fuenkajorn (2010) analyzed the changes of Young's modules, and Poison's ratio on salt rock under repeated load and unload procedures. Popp (2000) investigated the changes of rock's permeability and acoustic logging data under different stress load. In the studies concerned with the interaction between salt and drilling mud, Chen, X. analyzed the salt dissolving under WBM (Chen et al. 2011). De Meer, S. & C.J. Spiers studied the creeping rate of salt formation under WBM (De et a!. 1999). G & Baoping proposed a theoretical model incorporated the couple effects of thermal conduction and fluid infiltration on salt formation (Bao et al. 2008). To sum the above studies up, the previous studies have concluded that when the stress loading increases, the pre-existed internal micro cracks will expend (Chan et al. 2001).
- North America > Mexico (0.34)
- Asia > China (0.31)
- North America > United States (0.24)
- Research Report > New Finding (0.89)
- Research Report > Experimental Study (0.54)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.91)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (0.88)
- Well Drilling > Wellbore Design > Wellbore integrity (0.55)
Ultra-deep Multiple Salt-gypsum Formation In-situ Stress Prediction and Application in Casing Integrity Evaluation for Tarim Basin Piedmont Area
Du, J. L. (China University of Petroleum) | Jin, Y. (China University of Petroleum) | Chen, M. (China University of Petroleum) | Ge, W. F. (China University of Petroleum) | Lu, Y. H. (China University of Petroleum) | Liang, Ch. (China University of Petroleum) | Wang, X. Y. (China University of Petroleum)
Abstract As China's largest oil and gas bearing basin, the Tarim Basin has tremendous exploration and development potential. Piedmont area is the main producing area of the Tarim Basin, and single well production in this area is high. Multiple salt-gypsum formation, which consists of shale, salt, gypsum-mudstone, gypsum and other complex layers, is widely distributed in the piedmont area, which will cause drilling and completion engineering great challenges. Distinct from the character of low creep rate, simple deformation composition, high salt purity and low burying depth in North Sea, Gulf of Mexico, Brazil offshore, the salt-gypsum formation in Tarim Basin is buried in high depth of 7000m, the in-situ stress is at a high level of 150 MPa, and the formation temperature exceeds 160° C. In order to efficiently develop sub-salt reservoir, promoting sub-salt horizontal wells is necessary, but due to the characteristics of multiple salt-gypsum formation, previous sub-salt horizontal wells have low engineering success rate, restricting the development process of sub-salt reservoir. In-situ stress prediction in multiple salt-gypsum formation is a world class problem, based on the DRA-Kaiser experiment with field crop salt core, this paper established an innovative 3-D multi-layer complex geological model. It solved the problem that, the previous model during simulating process was oversimplified and could not truly reflect the actual geological structure. Based on the finite difference method and nonlinear prediction theory, a numerical method of in-situ stress field for whole regional composite salt-gypsum formation was developed. It overcame the problem that laboratory experiment and theoretical calculation were difficult to get in-situ stress of ultra-deep composite salt-gypsum formation, on this basis a 3-D bending casing-cement mantle-salt formation geological model is established, and further researched the effect on casing strain of borehole curvature, as well as the impact of non-uniform stress on the curved borehole casing in salt-gypsum formation. The research method in this paper can also be utilized in other ultra-deep sub-salt horizontal wells around the world.
- Europe (1.00)
- Asia > China > Xinjiang Uyghur Autonomous Region (1.00)
- Geology > Mineral > Sulfate > Gypsum (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.56)
- Materials > Construction Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)