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Experimental investigation of fracture-based wellbore strengthening using a large-scale true triaxial cell
Accepted Manuscript Experimental investigation of fracture-based wellbore strengthening using a largescale true triaxial cell Ruizhi Zhong, Stefan Miska, Mengjiao Yu, Meng Meng, Evren Ozbayoglu, Nicholas Takach PII:
S0920-4105(19)30325-0
DOI:
https://doi.org/10.1016/j.petrol.2019.03.081
Reference:
PETROL 5931
To appear in:
Journal of Petroleum Science and Engineering
Received Date: 11 December 2018 Revised Date:
29 March 2019
Accepted Date: 29 March 2019
Please cite this article as: Zhong, R., Miska, S., Yu, M., Meng, M., Ozbayoglu, E., Takach, N., Experimental investigation of fracture-based wellbore strengthening using a large-scale true triaxial cell, Journal of Petroleum Science and Engineering (2019), doi: https://doi.org/10.1016/j.petrol.2019.03.081. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
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Experimental Investigation of Fracture-Based Wellbore Strengthening Using a Large-Scale True Triaxial Cell
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Ruizhi ZhongA,C, Stefan MiskaB, Mengjiao YuB, Meng MengB, Evren OzbayogluB, Nicholas TakachB A
School of Chemical Engineering, The University of Queensland, Brisbane, QLD 4072, Australia
B
School of Petroleum Engineering, The University of Tulsa, 800 S Tucker Dr, Tulsa, OK 74104, United
C
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States Corresponding author. Email: [email protected]
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Abstract
Fracture-based wellbore strengthening is a widely used preventive technique for lost circulation control. However, there were limited experimental studies on wellbore strengthening with an anisotropic stress state. In this paper, we describe an experimental investigation )
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of fracture-based wellbore strengthening on cubic Berea sandstone samples (size of 12
using a large-scale true triaxial cell. The true triaxial cell allows fracture containment to simulate wellbore strengthening, which was not available using a traditional small-scale traixial cell. We used drill cuttings and Chevron loss prevention material (LPM) as wellbore
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strengthening materials (WSM). Three independent stresses were applied on the rock samples and bi-wing fractures were generated. The final fracture reopening pressure (FROP) exceeded
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the formation breakdown pressure (FBP) after plugging the WSM. Further comparison between the experimental results and modeling results from a numerical model shows a good match for the injection pressure profile.
1. Introduction Lost circulation occurs when the pumped drilling mud flows into natural or induced fractures instead of returning to the annulus (Chen et al. 2014). It is one of the major problems in the drilling industry and can cost $2-4 billion per year (Growcock 2010). In depleted 1
ACCEPTED MANUSCRIPT reservoirs, the pore pressure reduction due to hydrocarbon withdrawal can lead to a reduction of reservoir stresses (Addis 1997; Shahri and Miska 2013; Rafieepour et al. 2017; Chen et al. 2018; Meng et al. 2019a; Meng et al. 2019b). The lower in-situ stresses can lead to lower fracture gradient according to the tensile fracture criterion (Brudy and Zoback 1999; Majidi
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et al. 2015). Thus, drilling a new well in the depleted reservoirs can easily have lost circulation because of the induced fractures. Wellbore strengthening is a preventive technique that can increase the fracture gradient in weak zones. During the past several decades, fracture-based wellbore strengthening techniques such as fracture propagation resistance (Fuh et
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al. 1992; van Oort et al. 2011), stress cage (Alberty and Mclean 2004), and fracture closure stress (Dupriest 2005) have been proposed and applied to minimize lost circulation. The main
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idea is to plug the natural or induced fractures with customized plugging materials in the drilling mud. Then the fracture gradient can be increased. To achieve better wellbore strengthening effect, a study on wellbore strengthening has become a hot topic in the drilling industry. For the modeling of fracture-based wellbore strengthening, models can be categorized into analytical/semi-analytical methods and numerical methods. For the analyti-
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cal/semi-analytical modeling, fracture mechanics based methods have been employed to obtain the fracture geometry and fracture reopening pressure (Morita and Fuh 2012; Shahri et al 2014; Mehrabian et al. 2015; Feng and Gray 2016; Mehrabian and Abousleiman 2017). For
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the numerical methods, the finite element method (Alberty and Mclean 2004; Guo et al. 2011; Salehi and Nygaard 2012; Salehi and Nygaard 2014; Feng et al. 2015; Zhang et al. 2016; Zhao et al. 2017; Wang et al. 2017; Wang and Chen 2018) was mainly used to study fracture
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behavior and subsequently the wellbore strengthening effect. The boundary element method (Wang et al. 2007; Wang et al. 2009; Morita and Fuh 2012) was employed to perform some parametric studies on wellbore strengthening. Besides a number of analytical and numerical studies, there were some experimental
studies conducted on fracture-based wellbore strengthening. In general, there are two types of facilities used in the experimental study of wellbore strengthening: triaxial cell and true triaxial cell. Traditionally the triaxial cell is widely used for rock properties testing (Hoek and Franklin 1968; Jaeger et al. 2007). This facility can also be used for hydraulic fracturing if a hole is drilled inside the rock sample (Zhuang et al. 2016) and further used for wellbore 2
ACCEPTED MANUSCRIPT strengthening with accommodation of specialized drilling fluid. Aston et al. (2004) and Savari et al. (2014) used this facility for some fracture sealing experiments and observed some important effects of mud and rock properties (e.g., rock permeability, additives, and mud type) on sealing efficiency. Nwaoji et al. (2013) and Contreras et al. (2014) performed fracture
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plugging experiments using nanoparticle-based drilling fluids. Salehi and Kiran (2016) investigated plastering effects of wellbore strengthening due to mud cake buildup. Rahimi et al. (2016) conducted experimental studies and compared experimental results to five fracture width models. Razavi et al. (2016, 2017) and Cao et al. (2018) used a triaxial cell to test
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effect of types and partice size distribution (PSD) of wellbore strengthening materials (WSM) on wellbore strengthening. In summary, there have been some successes in using the triaxial
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cell for wellbore strengthening experiments. However, they are also several disadvantages. Firstly, there is no stress anisotropy in the horizontal direction, which can result in unstable fracture propagation (i.e., the fracture can propagate in an arbitrary horizontal direction). Furthermore, there is no fracture containment due to due the sample’s small scale. The fracture can easily propagate to the sample boundary and subsequently cause fluid loss on the
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boundary. The fractured boundaries raise concerns that experiments using a triaxial cell are technically simulating lost circulation control instead of wellbore strengthening. Hence, the previous experimental results may not be very accurate for wellbore strengthening applica-
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tions.
The second type of facility for wellbore strengthening is a true triaxial cell. This facility can accommodate small-scale cubic samples for rock properties testing (Haimson and
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Chang 2000) or large-scale cubic samples for hydraulic fracturing (Frash et al. 2014; Frash et al. 2015; Tan et al. 2017). In fact, the origin of wellbore strengthening techniques dates back to a 1980s joint industry project (JIP) known as the DEA-13, which used a large-scale true triaxial cell (sample size is 30
). The aim was to determine why oil-based mud (OBM)
seemed to have a lower fracture gradient than water-based mud (WBM) (Oniya 1994). The main difference was found to be the different types of filter cakes formed on the fracture surfaces when using WBM versus OBM. However, no further investigation was conducted on the effects of pore pressure, temperature, or plugging of WSM. A smaller true triaxial cell (sample size is 6
) was employed by Guo et al. (2014) to extensively test two types of 3
ACCEPTED MANUSCRIPT rocks: Grinshill sandstone and Runswick Bay shale. Wellbore strengthening was observed in some tests. For example, the formation breakdown pressure (FBP) was 867 psi using the base mud and the final peak pressure was 1678 psi after applying 30 lb/gal graphitic WSM. However, the fracture containment was poor because the fracture quickly propagated from the
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wellbore to the outer faces of the sample in their experiments. Because three independent stresses can be applied on the rock sample, the true triaxial cell has the ability to generate a bi-wing fracture with an anisotropic stress state, which can simulate downhole far-field stresses. However, the construction and operation of a true triaxial cell are generally more
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expensive and labor-intensive compared to a triaxial cell.
In summary, there have been a number of experimental studies using triaxial cells and triaxial
cells.
However,
we
still
lack
a
comprehensive
ther-
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true
mo-hydro-mechanical-chemical (THMC) understanding of wellbore strengthening. For instance, limited success has been achieved on shale wellbore strengthening (Guo et al. 2014; Gao et al. 2016). On the other hand, disregarding pore pressure and lack of temperature control are common problems due to manufacturing difficulties. In this paper, we developed a
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large-scale true triaxial cell to conduct wellbore strengthening experiments. The true triaxial can apply three independent stresses to simulate far-field stresses in the downhole condition, which allows the stable fracture propagation. Furthermore, the true triaxial cell allows frac-
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ture containment to simulate wellbore strengthening, which was not available using a traditional small-scale traixial cell. This experimental study serves as an initial investigation of coupled hydro-mechanical wellbore strengthening.
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The remainder of the paper is organized as follows: we first introduce the theories of
fracture-based wellbore strengthening. Then the experimental facilities (large-scale true triaxial cell and triaxial cell) and procedures are presented. Next, we detail the experimental results of two Berea sandstone samples and compare the experimental results with simulation results of a numerical model. The last section presents a summary of the work.
2. Theories of Fracture-based Wellbore Strengthening Over the past several decades, different fracture-based wellbore strengthening tech4
ACCEPTED MANUSCRIPT niques and theories have been proposed. These techniques mainly include fracture propagation resistance (Fuh et al. 1992; van Oort et al. 2011), stress cage (Alberty and Mclean 2004), and fracture closure stress (Dupriest 2005). In this section, we will briefly introduce these theories through schematics in Fig. 1.
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Fracture Propagation Resistance. This technique claims that WSM are pushed into an incipient or existing fracture to bridge, seal and isolate the fracture tip, thereby increasing the formation’s resistance to fracture propagation (Morita et al. 1990, Fuh et al. 1992, Fuh et al. 2007). This phenomenon is similar to fracture tip screenout during hydraulic fracturing. A
pressure is noted as
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schematic of the fracture propagation resistance model is shown in Fig. 1a. The wellbore . The origin of this methodology is a JIP known as DEA-13, whose
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purpose was to determine why OBM seemed to have a lower fracture propagation pressure (FPP) than WBM. The project found no difference in fracture initiation pressure with different drilling fluid type but there were notable differences in FPP. The differences were explained through a phenomenon called “fracture tip screen-out”. The fracture was sealed by an external filter-cake that prevents effective pressure communication between the WBM and
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the fracture tip. However, in a system using an OBM, an internal filter-cake allows for full pressure communication to the fracture tip, which facilitates fracture extension at a lower propagation pressures than a system with a WBM. The DEA-13 project also revealed that the
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composition and size distribution of particulates in the fluid were critically important to the success of applying fracture propagation resistance. Laboratory research conducted outside of the DEA-13 project resulted in the development of specialized WSM known as loss preven-
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tion material (LPM) that inhibited fracture tip growth (Fuh et al. 1992). Stress cage. The second technique is hoop stress enhancement method, which is com-
monly called the “stress cage” method (Alberty and Mclean 2004). Fig. 1b shows a schematic of the stress cage model. Unlike plugging particles at the fracture tip area in fracture propagation resistance theory, this technique states that the particles can be deposited at the fracture mouth after propping the fracture. Then the WSM can act as a seal to isolate the fluid pressure in the wellbore. Because the fluid pressure is higher than the pore pressure, and if the surrounding formation is sufficiently permeable in the isolated region, fluid will dissipate into the surrounding medium and pressure will decrease to the pore pressure. Therefore, the 5
ACCEPTED MANUSCRIPT fracture will attempt to close (closure fracture profile is shown in the dashed blue lines) and this can increase the hoop stress to exceed its original value. Fracture closure stress. Fracture closure stress technique was developed in the mid-1990s from industry practices. A fracture is opened when the wellbore pressure over-
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comes the sum of the stress holding the rock closed (fracture closure stress) and the tensile strength of the rock. This technique aims to increase the fracture closure stress after plugging WSM (Dupriest 2005). The theory of fracture closure stress states that an effective treatment should have fracture width building with high-fluid-loss WSM isolating the fracture tip,
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which can occur because of rapid drainage of carrier fluid from the mud mixture to the surrounding formation. The particles in the mud are compressed and agglomerate during the
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squeeze phase and then form a plug in the fracture, which cuts off the communication between the fracture tip and the wellbore. Then, an increase in the wellbore pressure can generate a wider fracture (enlarged fracture profile is shown in black dashed lines) and allow larger size WSM to be plugged. This process of hesitation squeeze ultimately achieves the fracture width building, as shown in Fig. 1c. To create the immobile mass for fracture width building,
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it is important that the particles are able to deform or be crushed.
The above theories explain the wellbore strengthening effect from different aspects. The major differences of these theories are the deployment procedure and WSM used in the
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wellbore strengthening (Cook et al. 2011). On the other hand, the similarity among these techniques is the goal to plug induced or preexisting fractures with a blend of WSM in the
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near-wellbore region.
3. Experimental Setup and Procedure 3.1 True Triaxial Cell
We have designed and constructed a large-scale true triaxial cell to conduct the wellbore strengthening experiments. This facility is similar to the true triaxial cell from Frash’s work (Frash et al. 2014; Frash et al. 2015). Fig. 2 shows the components and schematic of the true triaxial cell. Fig. 2a presents the main cell frame. There is a cubic hole in the middle to hold the rock sample. Fig. 2b shows the Teledyne pump, which serves as the fluid injection 6
ACCEPTED MANUSCRIPT system to create fractures. The maximum pressure is 4000 psi. The fluid injection rate (or pressure) can be precisely controlled by a LabVIEW program. Fig. 2c shows the hydraulic pumps, which are connected to the hydraulic flat jacks. Stresses up to 2000 psi can be applied through the hydraulic flat jacks. Fig. 2d shows the data acquisition system. A NI (National
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Instruments) data acquisition system was bought and coded to record the fluid pressure, injection rate and other data. Fig. 2e shows the cubic rock sample lifted by a hoist system. Finally, Fig. 2f shows the schematic of the true triaxial cell. Three independent stresses are applied to simulate downhole in-situ stresses and the drilled hole in the center is connected to
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the syringe pump for fracturing. 3.2 Triaxial Cell
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A smaller scale GCTS triaxial cell is used to measure some rock properties (e.g., Poisson’s ratio, Young’s modulus, and porosity). Fig. 3 shows the major components and schematic of the triaxial cell. Fig. 3a shows the pressure intensifiers. Two pressure intensifiers are used to control the pore pressure at the top and bottom of the sample and one pressure intensifier is used to control the confining pressure. These pressure intensifiers can boost the pres-
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sure up to 20000 psi. Fig. 3b shows the controlling and data acquisition system. Automated programs can be coded to conduct experiments and experimental data is recorded for analysis. Fig. 3c shows the hydraulic pump, which has a capacity of flow rate up to 10 gal/min and
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pressure up to 3000 psi. This pump is connected to the pressure intensifiers (in Fig. 3a), which can boost the original hydraulic pressure to the desired value. Fig. 3d shows the load
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frame of the triaxial cell. Axial force up to 500 kN (112404 lbf) can be applied to the core sample through a servo-controlled actuator in the load frame. Fig. 3e shows the schematic of the triaxial cell. A four-inch length and two-inch diameter cylindrical core sample (shown in brown) is used in the high-pressure cell. Two porous disks are applied on the top and bottom of the core sample to ensure the uniform pore fluid distribution. The core sample is also jacketed through a deformable heat shrink to isolate the confining fluid (mineral oil). Finally, the axial and radial strain measurement devices are mounted on the core sample to measure the deformation during the experiment.
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ACCEPTED MANUSCRIPT 3.3 Rock Samples and Wellbore Strengthening Materials We used concrete samples for preliminary experiments and two Berea sandstone samples for the formal experiments. The rock sample size is 12
. High strength epoxy was
used to ensure good bonding between the tubing and the rock sample. The WSM used in the experiments are composed of Chevron SURE-SEAL LPM (Fig. 4a) and drill cuttings from
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rock samples (Fig. 4b). The size of drill cuttings is much smaller than Chevron LPM, which gives the blend of WSM the ability to plug small fractures. The mixed WSM consist of half Chevron SURE-SEAL LPM and half drill cuttings. The concentration of formulated WSM is
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30 lb/bbl.
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4. Results and discussions
We have conducted experiments on two Berea sandstone samples. Significant time was spent on construction and calibration of the facility from scratch. Furthermore, it took up to one month to finish tests on one sample due to its large-scale, which leads to long preparation and disassembly. Nevertheless, we successfully observed higher fracture reopening pressure
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(FROP) than FBP for both samples. The experimental facility (large-scale true triaxial cell) does not have any pore pressure control. Thus, the linear elastic fracture mechanics can be used to explain the experimental results. The observed fractures are tensile fractures; however, it is possible that mix-mode fractures (i.e., tensile and shear fractures) may be induced for
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unconsolidated formations in shallow depth (Nguyen et al. 2011; Olson et al. 2011). The fol-
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lowing sections detail the results for these two samples.
4.1 First sample
There are several goals for the experiment on the first sample. The first goal is to see if
fractures can be arrested in the sample. Thus, an initial low injection rate was used (0.2 mL/min). Another goal is to test if wellbore strengthening effect exists after applying WSM by comparing the FROP with the FBP. The applied vertical stress, maximum horizontal stress, and minimum horizontal stress are 580 psi, 300 psi, and 110 psi, respectively. The fracture height is 3.5 in., which is the open hole section inside the rock sample. The pressure response (black lines) and injection rate (red dashed lines) of fracturing and refracturing experiments 8
ACCEPTED MANUSCRIPT before WSM plugging are shown in Fig. 5a. The injection rate was 0.2 mL/min. A typical hydraulic fracturing pressure pattern was observed with the FBP of 999 psi in the first injection experiment. Two refracturing experiments were conducted and the stabilized FPP was in the range of 400-450 psi. Hence, the rock tensile strength is about 600 psi if we compare the
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FBP and FPP. In general, it took several hours to perform a fracturing/refracturing experiment. Note that the complete pressure profile is not presented due to long falloff period after each experiment.
Then the original injection fluid was removed from the tubing and WSM were added in
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the new injection fluid to plug the fractures. To ensure the fluid in the plugged zone was depleted and enhance the fracture healing effect, the true triaxial cell was shut down for one day
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after WSM deposition. This is because the rock permeability is relatively low (0.5 mD according to the triaxial cell test), which can lead to long fluid leak-off time (Zhong et al. 2017a). Subsequently, two refracturing experiments were conducted. Two flow rates (0.2 mL/min and 0.5 mL/min) were used. The fluid pressure in both experiments had an increasing trend, as shown in Fig. 5b. The final FPP were 510.1 psi and 754.5 psi for the first
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and second refracturing experiment, respectively. Hence, there was a FPP increment due to the plugging of WSM because the original FPP was about 400 psi in Fig. 5a. However, the FPP did not exceed the FBP in Fig. 5a. This is because the plugged fracture length is short
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due to the refracturing experiment’s low injection rate and short refracturing time. The FROP is significantly dependent on the fracture plug location and length (Shahri 2015; Feng and Gray 2016b). Thus, in order to facilitate the process and enhance the wellbore strengthening
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effect, another refracturing experiment was conducted using a higher injection rate of 1 mL/min. The pressure response is shown in Fig. 5c. A similar pressure increasing trend was observed. The final FROP was 2215 psi, which was much higher than the FBP (999 psi). Thus, we observed the wellbore strengthening effect after plugging WSM. To see the induced fractures, the rock sample was split horizontally into two pieces, as shown in Fig. 6a. The directions of maximum and minimum horizontal stresses were denoted on the rock surface. The initial fracture orientation was not perfectly perpendicular to the direction of the minimum horizontal stress. This was probably because the drilled hole was not perfectly vertical or the applied three independent stresses are not orthogonal because this 9
ACCEPTED MANUSCRIPT facility is man-made. There were noticeable tortuosity effects due to the stress anisotropy. If the sample size is large enough and the fracture propagation time is long enough, the final fracture direction would probably be perpendicular to the direction of the minimum horizontal stress. Fig. 6b shows the close view of the wellbore and fractures. The fracture has two
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sections. We think that the first section was generated during propagation with low injection rate of 0.2 mL/min (the length is about one inch). The second section was generated with high flow rate of and 0.5 mL/min and 1 mL/min (the length is about three inches). The whole fracture was plugged with WSM. The process of WSM plugging in this experiment is similar
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to the hesitation squeeze in the theory of fracture closure stress (Dupriest 2005). The WSM can plug the entire or majority of the fracture and then the fluid pressure was gradually in-
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creased to reopen the fracture. After propagating a certain distance, the fracture was plugged by WSM again. This process was repeated as we observed an increasing jagged pressure profile in Fig. 5b and Fig 5c.
4.2 Second sample
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The main goal of experiment study on the second sample is to see if the wellbore strengthening effect is replicable with different initial conditions. A higher horizontal stress ratio was applied. The vertical stress, maximum horizontal stress, and minimum horizontal
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stress are 1180 psi, 800 psi, and 110 psi, respectively. The WSM were the same as those used in the last experiment, which were composed of Chevron SURE-SEAL LPM and drill cut-
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tings with the concentration of 30 lb/bbl. The injection rate for all experiments was 0.5 mL/min. Fig. 7a shows the fluid pressure (black lines) and the injection rate (red dashed line) without WSM. Similar to the experiments for the first sample, we conducted one fracturing experiment and two refracturing experiments. For the first fracturing experiment, the FBP was 1651.2 psi. The FPP was about 450 psi for the fracturing and two refracturing experiments. Fig. 7b shows the fluid pressure and injection rate after WSM plugging. The FROP was 2919.2 psi. Thus, additional 1267 psi was achieved by WSM plugging if we compare the FROP with the FBP. Unfortunately, we found a fluid leakage after we opened the true triaxial cell. This leakage was probably due to poor bonding between the tubing and rock sample. Hence, no jagged pressure increase was observed in this experiment. 10
ACCEPTED MANUSCRIPT Fig. 8a shows the split sample with fractures and Fig. 8b shows the close view of the wellbore and fractures. There are two sets of fractures (two short fractures and two long fractures). We think that the two short fractures are induced without fractures and the two long fractures were propagated with WSM. After plugging of WSM, it is possible that the stress
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distribution was changed, and the new weakest point may not be on the original fracture surface (Mehrabian et al. 2015). The short fractures propagated perpendicular to the direction of the minimum horizontal stress. However, the long fractures diverted a little from the direction of maximum horizontal stress. The length of a single long fracture is about 3.5 inches. To
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have a better observation of fracture plugging, Fig. 9 shows two magnified photographs of a
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fracture with WSM. The WSM (light materials in the figure) have plugged the fracture.
4.3 Evaluation of a numerical model using experimental results Recently, we developed a numerical model to estimate the near-wellbore fracture geometry for wellbore strengthening (Zhong et al. 2017b; Zhong et al. 2018). The numerical model is based on the fracture mechanics (Warren 1982; Carbonell and Detournay 1995;
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Shahri et al. 2014) and couples the fluid flow. To evaluate the model performance, we run the program and compare simulation results with the experimental results of the first sample. The parameters used in the simulation are shown in Table 1. These parameters are based on experimental setup, rock mechanics testing, and reasonable estimations of permeability and
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stress intensity factor for Berea Sandstone (Nara et al. 2012). Fig. 10 shows the fluid pressure from simulation results and experimental results be-
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fore plugging of WSM. The simulation results are shown in the red line and experimental results are shown in the black line. Note that we combined the fluid pressure of fracturing and refracturing cycles in Fig. 5a to form the black line in Fig. 10. As the black line is almost seamless, we can regard this as a single fracture propagation. A good match between the simulation results and experimental results is obtained, especially in the later stages of fracturing. The simulated fracture length is 1.495 in., which is longer than 1 in. fracture length (the first section of fracture in Fig. 6b) from the experimental results. Fig. 11 shows the fracture mouth width with time evolution. The final fracture mouth width is 29.5 μm, which indicates that the WSM plugged in the fractures are mostly small-size drill cuttings. 11
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4.4 Implication of the findings on field application Both experiments described in Section 4.1 and 4.2 showed a higher FROP than FBP after plugging WSM. Thus, the wellbore strengthening effect has been demonstrated using
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the constructed true triaxial cell. This facility allows application of three independent stresses to simulate far-field stresses and fracture containment compared to the commonly used small-scale triaxial cell. Furthermore, this facility is cost effective as a commercial large-scale true triaxial cell costs 0.5-1.5 million dollars. Regarding the experimental results,
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both experiments showed that WSM have plugged the whole fracture and achieved good pressure increment. Thus, a WSM pill with low injection rate may be used in field application.
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Moreover, in the experiments on the second sample, we observed the stress redistribution from two sets of fractures after plugging of WSM, which was not found in previous laboratory experiments or field testing to author’s knowledge. In the future, drilling mud with different types and concentration of WSM can be tested to quantify the wellbore strengthening effect. To better simulate field wellbore strengthening operation (if not considering the up-
5. Conclusions
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scaling effects), functions such as pore pressure and temperature control should be included.
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In this paper, wellbore strengthening experiments were performed on two Berea sandstone samples using a large-scale true triaxial cell. We used drill cuttings and Chevron LPM
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as WSM. The following conclusions can be drawn from this study: 1. Bi-wing fractures were generated in both samples due to the stress anisotropy provided by the true triaxial cell. The fractures were contained inside the rock sample by limiting the fluid injection rate under 1 mL/min.
2. For the first sample, the FBP was 999 psi. Three injection rates were applied After WSM plugging, an increasing jagged pressure trend was observed during the fracture propagation stage. The FROP was 2230.5 psi, which was 1231.5 psi higher than the FBP. 3. For the second sample, a higher horizontal stress ratio was applied. A constant in12
ACCEPTED MANUSCRIPT jection rate 0.5 mL/min was applied before and after WSM plugging. The FBP was 1651.2 psi and FROP is 2919.2 psi. Two set of fractures (two short fractures and two long fractures) were generated, which indicates the plugging of WSM can change stress distribution and the weakest point for fracture propagation. The mag-
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nified photographs show that the WSM plug the whole fracture. 4. The fracturing pressure profile from the first sample was compared to simulation results from a numerical model, which shows a very good match for the injection pressure. The proposed numerical model can be used to estimate the fracture geom-
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etry for wellbore strengthening design.
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Acknowledgements
The authors are grateful to the University of Tulsa Drilling Research Projects (TUDRP)
Abbreviations
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Formation breakdown pressure Fracture propagation pressure Fracture reopening pressure Joint industry project Lost preventive material Oil-based mud Particle size distribution Thermo-hydro-mechanical-chemical Water-based mud Wellbore strengthening materials
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FBP FPP FROP JIP LPM OBM PSD THMC WBM WSM
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member companies for their technical and financial support.
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Appendix A. Experimental Procedure
Due to the nature of the experiment (high pressure and large-scale), it is important to
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implement safe procedures. The following are brief procedures to conduct a fracturing experiment:
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(1). Prepare the rock sample. This step mainly includes drilling a hole in the sample and bonding the tubing to the rock sample.
(2). Load the rock sample into the cell. There are several steps involved in this step. First, we need to place spacers, hydraulic flat jacks and steel plates in the cell. The rock sample can be lifted by a hoist system from the ground into the true triaxial cell. Then, the cement
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mix is poured to fill the gaps between the rock sample and cubic grout surfaces to ensure full contact. Next, the top steel plate and the cell lid are placed on the top of the rock sample. Finally, we need to connect the tubing with the hydraulic pumps and Teledyne pump. (3). Run computer programs. There are two LabVIEW programs. The first program is
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for Teledyne pump control. Another LabVIEW program is used for monitoring and recording the pressure of hydraulic pumps. The parameters in the programs should be modified if there
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are any changes in a new experiment. (4). Apply three principal stresses using the hydraulic pumps. Manually pump three
hydraulic pumps to the desired pressures. Record the data using the LabVIEW program. (5). Inject the fluid into the rock sample using the Teledyne pump. If the Teledyne
pump is empty, it requires refill before injection. Once the pump is on, we need to monitor the pattern of the fluid injection pressure. During the early stage, there should be a pressure build up period. When the rock sample breaks down, a sharp pressure decline is expected. After significant pressure drop, the fluid pressure will keep almost constant (i.e., stable FPP). (6). Shut down the pumps and unload the cell. First, the injection pressure should be 22
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The above procedures can be repeated to refracture the rock. For wellbore strengthen-
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Fig. 1. Schematic of wellbore strengthening models. (a) Fracture propagation resistance. (b) Stress cage. (c) Fracture closure stress.
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Fig. 2. Components of the true triaxial cell. (a) Main cell frame. (b) Teledyne pump for fluid injection. (c) Hydraulic pumps for confining stress control. (d) Data acquisition system. (e) Cubic rock sample. (f) Schematic of the true triaxial cell.
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Fig. 3. Components of the triaxial cell. (a) Pore pressure and confining pressure intensifiers. (b) Data acquisition system. (c) Hydraulic pump. (d) Load frame. (e) Schematic of the triaxial cell.
Fig. 4. Wellbore strengthening materials. (a) Chevron loss prevention material (LPM). (b) Drill cuttings.
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Fig. 5. Fluid pressure response and injection rate for the first sample (black lines: fluid pressure; red dashed lines: injection rate). (a) Before WSM plugging. (b) After WSM plugging with a flow rate of 0.2 mL/min and 0.5 mL/min. (c) After WSM plugging with a flow rate of 1 mL/min. (WSM: wellbore strengthening materials).
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Fig. 6. (a) Split samples with bi-wing fractures for the first sample. The directions of maximum and minimum horizontal stresses were denoted on the rock surfaces. (b) Close view of the wellbore and fractures.
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Fig. 7. Fluid pressure response and injection rate for the second sample (black lines: fluid pressure; red dashed lines: injection rate). (a) Before WSM plugging. (b) After WSM plugging. (WSM: wellbore strengthening materials). Fig. 8. (a) Split samples with bi-wing fractures for the second sample. The directions of maximum and minimum horizontal stresses were denoted on the rock surface. (b) Close view of the wellbore and fractures.
Fig. 9. (a) Magnified view of a fracture with WSM for the second sample. (b) Higher magnified view of a fracture with WSM. (WSM: wellbore strengthening materials). Fig. 10. Comparison of fluid pressure of the first sample from simulation results and experimental results. 24
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Parameters
Value
Chebyshev polynomial term, m Young’s Modulus, E
50
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Fig. 11. Fracture mouth width of the first sample from simulation results.
1.53E6 psi 0.056
Wellbore radius, a
0.125 in.
Pore pressure, P
0 psi
Injection rate, Q
0.2 mL/min
Fluid viscosity, μ
300 cp
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Rock permeability, k
0.5 md
Rock porosity, ∅
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Fracture height, H
3.5 in.
Vertical stress, σ
580 psi
Maximum horizontal stress, σ
300 psi
Minimum horizontal stress, σ
110 psi
Wellbore inclination, I
0
Wellbore azimuth, A
0
Fracture toughness, K
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600 psi·√in.
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Table 1. Input parameters used in the simulation.
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Highlights
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Experimental investigation of fracture-based wellbore strengthening was conducted on a large-scale true triaxial cell. Fracture reopening pressures were higher than formation breakdown pressures. Results of induced and plugged fractures were shown.
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Stress redistribution was observed with plugging of wellbore strengthening materials.
S0920-4105(19)30325-0
DOI:
https://doi.org/10.1016/j.petrol.2019.03.081
Reference:
PETROL 5931
To appear in:
Journal of Petroleum Science and Engineering
Received Date: 11 December 2018 Revised Date:
29 March 2019
Accepted Date: 29 March 2019
Please cite this article as: Zhong, R., Miska, S., Yu, M., Meng, M., Ozbayoglu, E., Takach, N., Experimental investigation of fracture-based wellbore strengthening using a large-scale true triaxial cell, Journal of Petroleum Science and Engineering (2019), doi: https://doi.org/10.1016/j.petrol.2019.03.081. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
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Experimental Investigation of Fracture-Based Wellbore Strengthening Using a Large-Scale True Triaxial Cell
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Ruizhi ZhongA,C, Stefan MiskaB, Mengjiao YuB, Meng MengB, Evren OzbayogluB, Nicholas TakachB A
School of Chemical Engineering, The University of Queensland, Brisbane, QLD 4072, Australia
B
School of Petroleum Engineering, The University of Tulsa, 800 S Tucker Dr, Tulsa, OK 74104, United
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States Corresponding author. Email: [email protected]
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Abstract
Fracture-based wellbore strengthening is a widely used preventive technique for lost circulation control. However, there were limited experimental studies on wellbore strengthening with an anisotropic stress state. In this paper, we describe an experimental investigation )
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of fracture-based wellbore strengthening on cubic Berea sandstone samples (size of 12
using a large-scale true triaxial cell. The true triaxial cell allows fracture containment to simulate wellbore strengthening, which was not available using a traditional small-scale traixial cell. We used drill cuttings and Chevron loss prevention material (LPM) as wellbore
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strengthening materials (WSM). Three independent stresses were applied on the rock samples and bi-wing fractures were generated. The final fracture reopening pressure (FROP) exceeded
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the formation breakdown pressure (FBP) after plugging the WSM. Further comparison between the experimental results and modeling results from a numerical model shows a good match for the injection pressure profile.
1. Introduction Lost circulation occurs when the pumped drilling mud flows into natural or induced fractures instead of returning to the annulus (Chen et al. 2014). It is one of the major problems in the drilling industry and can cost $2-4 billion per year (Growcock 2010). In depleted 1
ACCEPTED MANUSCRIPT reservoirs, the pore pressure reduction due to hydrocarbon withdrawal can lead to a reduction of reservoir stresses (Addis 1997; Shahri and Miska 2013; Rafieepour et al. 2017; Chen et al. 2018; Meng et al. 2019a; Meng et al. 2019b). The lower in-situ stresses can lead to lower fracture gradient according to the tensile fracture criterion (Brudy and Zoback 1999; Majidi
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et al. 2015). Thus, drilling a new well in the depleted reservoirs can easily have lost circulation because of the induced fractures. Wellbore strengthening is a preventive technique that can increase the fracture gradient in weak zones. During the past several decades, fracture-based wellbore strengthening techniques such as fracture propagation resistance (Fuh et
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al. 1992; van Oort et al. 2011), stress cage (Alberty and Mclean 2004), and fracture closure stress (Dupriest 2005) have been proposed and applied to minimize lost circulation. The main
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idea is to plug the natural or induced fractures with customized plugging materials in the drilling mud. Then the fracture gradient can be increased. To achieve better wellbore strengthening effect, a study on wellbore strengthening has become a hot topic in the drilling industry. For the modeling of fracture-based wellbore strengthening, models can be categorized into analytical/semi-analytical methods and numerical methods. For the analyti-
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cal/semi-analytical modeling, fracture mechanics based methods have been employed to obtain the fracture geometry and fracture reopening pressure (Morita and Fuh 2012; Shahri et al 2014; Mehrabian et al. 2015; Feng and Gray 2016; Mehrabian and Abousleiman 2017). For
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the numerical methods, the finite element method (Alberty and Mclean 2004; Guo et al. 2011; Salehi and Nygaard 2012; Salehi and Nygaard 2014; Feng et al. 2015; Zhang et al. 2016; Zhao et al. 2017; Wang et al. 2017; Wang and Chen 2018) was mainly used to study fracture
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behavior and subsequently the wellbore strengthening effect. The boundary element method (Wang et al. 2007; Wang et al. 2009; Morita and Fuh 2012) was employed to perform some parametric studies on wellbore strengthening. Besides a number of analytical and numerical studies, there were some experimental
studies conducted on fracture-based wellbore strengthening. In general, there are two types of facilities used in the experimental study of wellbore strengthening: triaxial cell and true triaxial cell. Traditionally the triaxial cell is widely used for rock properties testing (Hoek and Franklin 1968; Jaeger et al. 2007). This facility can also be used for hydraulic fracturing if a hole is drilled inside the rock sample (Zhuang et al. 2016) and further used for wellbore 2
ACCEPTED MANUSCRIPT strengthening with accommodation of specialized drilling fluid. Aston et al. (2004) and Savari et al. (2014) used this facility for some fracture sealing experiments and observed some important effects of mud and rock properties (e.g., rock permeability, additives, and mud type) on sealing efficiency. Nwaoji et al. (2013) and Contreras et al. (2014) performed fracture
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plugging experiments using nanoparticle-based drilling fluids. Salehi and Kiran (2016) investigated plastering effects of wellbore strengthening due to mud cake buildup. Rahimi et al. (2016) conducted experimental studies and compared experimental results to five fracture width models. Razavi et al. (2016, 2017) and Cao et al. (2018) used a triaxial cell to test
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effect of types and partice size distribution (PSD) of wellbore strengthening materials (WSM) on wellbore strengthening. In summary, there have been some successes in using the triaxial
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cell for wellbore strengthening experiments. However, they are also several disadvantages. Firstly, there is no stress anisotropy in the horizontal direction, which can result in unstable fracture propagation (i.e., the fracture can propagate in an arbitrary horizontal direction). Furthermore, there is no fracture containment due to due the sample’s small scale. The fracture can easily propagate to the sample boundary and subsequently cause fluid loss on the
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boundary. The fractured boundaries raise concerns that experiments using a triaxial cell are technically simulating lost circulation control instead of wellbore strengthening. Hence, the previous experimental results may not be very accurate for wellbore strengthening applica-
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tions.
The second type of facility for wellbore strengthening is a true triaxial cell. This facility can accommodate small-scale cubic samples for rock properties testing (Haimson and
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Chang 2000) or large-scale cubic samples for hydraulic fracturing (Frash et al. 2014; Frash et al. 2015; Tan et al. 2017). In fact, the origin of wellbore strengthening techniques dates back to a 1980s joint industry project (JIP) known as the DEA-13, which used a large-scale true triaxial cell (sample size is 30
). The aim was to determine why oil-based mud (OBM)
seemed to have a lower fracture gradient than water-based mud (WBM) (Oniya 1994). The main difference was found to be the different types of filter cakes formed on the fracture surfaces when using WBM versus OBM. However, no further investigation was conducted on the effects of pore pressure, temperature, or plugging of WSM. A smaller true triaxial cell (sample size is 6
) was employed by Guo et al. (2014) to extensively test two types of 3
ACCEPTED MANUSCRIPT rocks: Grinshill sandstone and Runswick Bay shale. Wellbore strengthening was observed in some tests. For example, the formation breakdown pressure (FBP) was 867 psi using the base mud and the final peak pressure was 1678 psi after applying 30 lb/gal graphitic WSM. However, the fracture containment was poor because the fracture quickly propagated from the
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wellbore to the outer faces of the sample in their experiments. Because three independent stresses can be applied on the rock sample, the true triaxial cell has the ability to generate a bi-wing fracture with an anisotropic stress state, which can simulate downhole far-field stresses. However, the construction and operation of a true triaxial cell are generally more
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expensive and labor-intensive compared to a triaxial cell.
In summary, there have been a number of experimental studies using triaxial cells and triaxial
cells.
However,
we
still
lack
a
comprehensive
ther-
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true
mo-hydro-mechanical-chemical (THMC) understanding of wellbore strengthening. For instance, limited success has been achieved on shale wellbore strengthening (Guo et al. 2014; Gao et al. 2016). On the other hand, disregarding pore pressure and lack of temperature control are common problems due to manufacturing difficulties. In this paper, we developed a
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large-scale true triaxial cell to conduct wellbore strengthening experiments. The true triaxial can apply three independent stresses to simulate far-field stresses in the downhole condition, which allows the stable fracture propagation. Furthermore, the true triaxial cell allows frac-
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ture containment to simulate wellbore strengthening, which was not available using a traditional small-scale traixial cell. This experimental study serves as an initial investigation of coupled hydro-mechanical wellbore strengthening.
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The remainder of the paper is organized as follows: we first introduce the theories of
fracture-based wellbore strengthening. Then the experimental facilities (large-scale true triaxial cell and triaxial cell) and procedures are presented. Next, we detail the experimental results of two Berea sandstone samples and compare the experimental results with simulation results of a numerical model. The last section presents a summary of the work.
2. Theories of Fracture-based Wellbore Strengthening Over the past several decades, different fracture-based wellbore strengthening tech4
ACCEPTED MANUSCRIPT niques and theories have been proposed. These techniques mainly include fracture propagation resistance (Fuh et al. 1992; van Oort et al. 2011), stress cage (Alberty and Mclean 2004), and fracture closure stress (Dupriest 2005). In this section, we will briefly introduce these theories through schematics in Fig. 1.
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Fracture Propagation Resistance. This technique claims that WSM are pushed into an incipient or existing fracture to bridge, seal and isolate the fracture tip, thereby increasing the formation’s resistance to fracture propagation (Morita et al. 1990, Fuh et al. 1992, Fuh et al. 2007). This phenomenon is similar to fracture tip screenout during hydraulic fracturing. A
pressure is noted as
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schematic of the fracture propagation resistance model is shown in Fig. 1a. The wellbore . The origin of this methodology is a JIP known as DEA-13, whose
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purpose was to determine why OBM seemed to have a lower fracture propagation pressure (FPP) than WBM. The project found no difference in fracture initiation pressure with different drilling fluid type but there were notable differences in FPP. The differences were explained through a phenomenon called “fracture tip screen-out”. The fracture was sealed by an external filter-cake that prevents effective pressure communication between the WBM and
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the fracture tip. However, in a system using an OBM, an internal filter-cake allows for full pressure communication to the fracture tip, which facilitates fracture extension at a lower propagation pressures than a system with a WBM. The DEA-13 project also revealed that the
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composition and size distribution of particulates in the fluid were critically important to the success of applying fracture propagation resistance. Laboratory research conducted outside of the DEA-13 project resulted in the development of specialized WSM known as loss preven-
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tion material (LPM) that inhibited fracture tip growth (Fuh et al. 1992). Stress cage. The second technique is hoop stress enhancement method, which is com-
monly called the “stress cage” method (Alberty and Mclean 2004). Fig. 1b shows a schematic of the stress cage model. Unlike plugging particles at the fracture tip area in fracture propagation resistance theory, this technique states that the particles can be deposited at the fracture mouth after propping the fracture. Then the WSM can act as a seal to isolate the fluid pressure in the wellbore. Because the fluid pressure is higher than the pore pressure, and if the surrounding formation is sufficiently permeable in the isolated region, fluid will dissipate into the surrounding medium and pressure will decrease to the pore pressure. Therefore, the 5
ACCEPTED MANUSCRIPT fracture will attempt to close (closure fracture profile is shown in the dashed blue lines) and this can increase the hoop stress to exceed its original value. Fracture closure stress. Fracture closure stress technique was developed in the mid-1990s from industry practices. A fracture is opened when the wellbore pressure over-
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comes the sum of the stress holding the rock closed (fracture closure stress) and the tensile strength of the rock. This technique aims to increase the fracture closure stress after plugging WSM (Dupriest 2005). The theory of fracture closure stress states that an effective treatment should have fracture width building with high-fluid-loss WSM isolating the fracture tip,
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which can occur because of rapid drainage of carrier fluid from the mud mixture to the surrounding formation. The particles in the mud are compressed and agglomerate during the
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squeeze phase and then form a plug in the fracture, which cuts off the communication between the fracture tip and the wellbore. Then, an increase in the wellbore pressure can generate a wider fracture (enlarged fracture profile is shown in black dashed lines) and allow larger size WSM to be plugged. This process of hesitation squeeze ultimately achieves the fracture width building, as shown in Fig. 1c. To create the immobile mass for fracture width building,
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it is important that the particles are able to deform or be crushed.
The above theories explain the wellbore strengthening effect from different aspects. The major differences of these theories are the deployment procedure and WSM used in the
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wellbore strengthening (Cook et al. 2011). On the other hand, the similarity among these techniques is the goal to plug induced or preexisting fractures with a blend of WSM in the
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near-wellbore region.
3. Experimental Setup and Procedure 3.1 True Triaxial Cell
We have designed and constructed a large-scale true triaxial cell to conduct the wellbore strengthening experiments. This facility is similar to the true triaxial cell from Frash’s work (Frash et al. 2014; Frash et al. 2015). Fig. 2 shows the components and schematic of the true triaxial cell. Fig. 2a presents the main cell frame. There is a cubic hole in the middle to hold the rock sample. Fig. 2b shows the Teledyne pump, which serves as the fluid injection 6
ACCEPTED MANUSCRIPT system to create fractures. The maximum pressure is 4000 psi. The fluid injection rate (or pressure) can be precisely controlled by a LabVIEW program. Fig. 2c shows the hydraulic pumps, which are connected to the hydraulic flat jacks. Stresses up to 2000 psi can be applied through the hydraulic flat jacks. Fig. 2d shows the data acquisition system. A NI (National
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Instruments) data acquisition system was bought and coded to record the fluid pressure, injection rate and other data. Fig. 2e shows the cubic rock sample lifted by a hoist system. Finally, Fig. 2f shows the schematic of the true triaxial cell. Three independent stresses are applied to simulate downhole in-situ stresses and the drilled hole in the center is connected to
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the syringe pump for fracturing. 3.2 Triaxial Cell
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A smaller scale GCTS triaxial cell is used to measure some rock properties (e.g., Poisson’s ratio, Young’s modulus, and porosity). Fig. 3 shows the major components and schematic of the triaxial cell. Fig. 3a shows the pressure intensifiers. Two pressure intensifiers are used to control the pore pressure at the top and bottom of the sample and one pressure intensifier is used to control the confining pressure. These pressure intensifiers can boost the pres-
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sure up to 20000 psi. Fig. 3b shows the controlling and data acquisition system. Automated programs can be coded to conduct experiments and experimental data is recorded for analysis. Fig. 3c shows the hydraulic pump, which has a capacity of flow rate up to 10 gal/min and
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pressure up to 3000 psi. This pump is connected to the pressure intensifiers (in Fig. 3a), which can boost the original hydraulic pressure to the desired value. Fig. 3d shows the load
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frame of the triaxial cell. Axial force up to 500 kN (112404 lbf) can be applied to the core sample through a servo-controlled actuator in the load frame. Fig. 3e shows the schematic of the triaxial cell. A four-inch length and two-inch diameter cylindrical core sample (shown in brown) is used in the high-pressure cell. Two porous disks are applied on the top and bottom of the core sample to ensure the uniform pore fluid distribution. The core sample is also jacketed through a deformable heat shrink to isolate the confining fluid (mineral oil). Finally, the axial and radial strain measurement devices are mounted on the core sample to measure the deformation during the experiment.
7
ACCEPTED MANUSCRIPT 3.3 Rock Samples and Wellbore Strengthening Materials We used concrete samples for preliminary experiments and two Berea sandstone samples for the formal experiments. The rock sample size is 12
. High strength epoxy was
used to ensure good bonding between the tubing and the rock sample. The WSM used in the experiments are composed of Chevron SURE-SEAL LPM (Fig. 4a) and drill cuttings from
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rock samples (Fig. 4b). The size of drill cuttings is much smaller than Chevron LPM, which gives the blend of WSM the ability to plug small fractures. The mixed WSM consist of half Chevron SURE-SEAL LPM and half drill cuttings. The concentration of formulated WSM is
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30 lb/bbl.
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4. Results and discussions
We have conducted experiments on two Berea sandstone samples. Significant time was spent on construction and calibration of the facility from scratch. Furthermore, it took up to one month to finish tests on one sample due to its large-scale, which leads to long preparation and disassembly. Nevertheless, we successfully observed higher fracture reopening pressure
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(FROP) than FBP for both samples. The experimental facility (large-scale true triaxial cell) does not have any pore pressure control. Thus, the linear elastic fracture mechanics can be used to explain the experimental results. The observed fractures are tensile fractures; however, it is possible that mix-mode fractures (i.e., tensile and shear fractures) may be induced for
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unconsolidated formations in shallow depth (Nguyen et al. 2011; Olson et al. 2011). The fol-
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lowing sections detail the results for these two samples.
4.1 First sample
There are several goals for the experiment on the first sample. The first goal is to see if
fractures can be arrested in the sample. Thus, an initial low injection rate was used (0.2 mL/min). Another goal is to test if wellbore strengthening effect exists after applying WSM by comparing the FROP with the FBP. The applied vertical stress, maximum horizontal stress, and minimum horizontal stress are 580 psi, 300 psi, and 110 psi, respectively. The fracture height is 3.5 in., which is the open hole section inside the rock sample. The pressure response (black lines) and injection rate (red dashed lines) of fracturing and refracturing experiments 8
ACCEPTED MANUSCRIPT before WSM plugging are shown in Fig. 5a. The injection rate was 0.2 mL/min. A typical hydraulic fracturing pressure pattern was observed with the FBP of 999 psi in the first injection experiment. Two refracturing experiments were conducted and the stabilized FPP was in the range of 400-450 psi. Hence, the rock tensile strength is about 600 psi if we compare the
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FBP and FPP. In general, it took several hours to perform a fracturing/refracturing experiment. Note that the complete pressure profile is not presented due to long falloff period after each experiment.
Then the original injection fluid was removed from the tubing and WSM were added in
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the new injection fluid to plug the fractures. To ensure the fluid in the plugged zone was depleted and enhance the fracture healing effect, the true triaxial cell was shut down for one day
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after WSM deposition. This is because the rock permeability is relatively low (0.5 mD according to the triaxial cell test), which can lead to long fluid leak-off time (Zhong et al. 2017a). Subsequently, two refracturing experiments were conducted. Two flow rates (0.2 mL/min and 0.5 mL/min) were used. The fluid pressure in both experiments had an increasing trend, as shown in Fig. 5b. The final FPP were 510.1 psi and 754.5 psi for the first
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and second refracturing experiment, respectively. Hence, there was a FPP increment due to the plugging of WSM because the original FPP was about 400 psi in Fig. 5a. However, the FPP did not exceed the FBP in Fig. 5a. This is because the plugged fracture length is short
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due to the refracturing experiment’s low injection rate and short refracturing time. The FROP is significantly dependent on the fracture plug location and length (Shahri 2015; Feng and Gray 2016b). Thus, in order to facilitate the process and enhance the wellbore strengthening
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effect, another refracturing experiment was conducted using a higher injection rate of 1 mL/min. The pressure response is shown in Fig. 5c. A similar pressure increasing trend was observed. The final FROP was 2215 psi, which was much higher than the FBP (999 psi). Thus, we observed the wellbore strengthening effect after plugging WSM. To see the induced fractures, the rock sample was split horizontally into two pieces, as shown in Fig. 6a. The directions of maximum and minimum horizontal stresses were denoted on the rock surface. The initial fracture orientation was not perfectly perpendicular to the direction of the minimum horizontal stress. This was probably because the drilled hole was not perfectly vertical or the applied three independent stresses are not orthogonal because this 9
ACCEPTED MANUSCRIPT facility is man-made. There were noticeable tortuosity effects due to the stress anisotropy. If the sample size is large enough and the fracture propagation time is long enough, the final fracture direction would probably be perpendicular to the direction of the minimum horizontal stress. Fig. 6b shows the close view of the wellbore and fractures. The fracture has two
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sections. We think that the first section was generated during propagation with low injection rate of 0.2 mL/min (the length is about one inch). The second section was generated with high flow rate of and 0.5 mL/min and 1 mL/min (the length is about three inches). The whole fracture was plugged with WSM. The process of WSM plugging in this experiment is similar
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to the hesitation squeeze in the theory of fracture closure stress (Dupriest 2005). The WSM can plug the entire or majority of the fracture and then the fluid pressure was gradually in-
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creased to reopen the fracture. After propagating a certain distance, the fracture was plugged by WSM again. This process was repeated as we observed an increasing jagged pressure profile in Fig. 5b and Fig 5c.
4.2 Second sample
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The main goal of experiment study on the second sample is to see if the wellbore strengthening effect is replicable with different initial conditions. A higher horizontal stress ratio was applied. The vertical stress, maximum horizontal stress, and minimum horizontal
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stress are 1180 psi, 800 psi, and 110 psi, respectively. The WSM were the same as those used in the last experiment, which were composed of Chevron SURE-SEAL LPM and drill cut-
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tings with the concentration of 30 lb/bbl. The injection rate for all experiments was 0.5 mL/min. Fig. 7a shows the fluid pressure (black lines) and the injection rate (red dashed line) without WSM. Similar to the experiments for the first sample, we conducted one fracturing experiment and two refracturing experiments. For the first fracturing experiment, the FBP was 1651.2 psi. The FPP was about 450 psi for the fracturing and two refracturing experiments. Fig. 7b shows the fluid pressure and injection rate after WSM plugging. The FROP was 2919.2 psi. Thus, additional 1267 psi was achieved by WSM plugging if we compare the FROP with the FBP. Unfortunately, we found a fluid leakage after we opened the true triaxial cell. This leakage was probably due to poor bonding between the tubing and rock sample. Hence, no jagged pressure increase was observed in this experiment. 10
ACCEPTED MANUSCRIPT Fig. 8a shows the split sample with fractures and Fig. 8b shows the close view of the wellbore and fractures. There are two sets of fractures (two short fractures and two long fractures). We think that the two short fractures are induced without fractures and the two long fractures were propagated with WSM. After plugging of WSM, it is possible that the stress
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distribution was changed, and the new weakest point may not be on the original fracture surface (Mehrabian et al. 2015). The short fractures propagated perpendicular to the direction of the minimum horizontal stress. However, the long fractures diverted a little from the direction of maximum horizontal stress. The length of a single long fracture is about 3.5 inches. To
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have a better observation of fracture plugging, Fig. 9 shows two magnified photographs of a
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fracture with WSM. The WSM (light materials in the figure) have plugged the fracture.
4.3 Evaluation of a numerical model using experimental results Recently, we developed a numerical model to estimate the near-wellbore fracture geometry for wellbore strengthening (Zhong et al. 2017b; Zhong et al. 2018). The numerical model is based on the fracture mechanics (Warren 1982; Carbonell and Detournay 1995;
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Shahri et al. 2014) and couples the fluid flow. To evaluate the model performance, we run the program and compare simulation results with the experimental results of the first sample. The parameters used in the simulation are shown in Table 1. These parameters are based on experimental setup, rock mechanics testing, and reasonable estimations of permeability and
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stress intensity factor for Berea Sandstone (Nara et al. 2012). Fig. 10 shows the fluid pressure from simulation results and experimental results be-
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fore plugging of WSM. The simulation results are shown in the red line and experimental results are shown in the black line. Note that we combined the fluid pressure of fracturing and refracturing cycles in Fig. 5a to form the black line in Fig. 10. As the black line is almost seamless, we can regard this as a single fracture propagation. A good match between the simulation results and experimental results is obtained, especially in the later stages of fracturing. The simulated fracture length is 1.495 in., which is longer than 1 in. fracture length (the first section of fracture in Fig. 6b) from the experimental results. Fig. 11 shows the fracture mouth width with time evolution. The final fracture mouth width is 29.5 μm, which indicates that the WSM plugged in the fractures are mostly small-size drill cuttings. 11
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4.4 Implication of the findings on field application Both experiments described in Section 4.1 and 4.2 showed a higher FROP than FBP after plugging WSM. Thus, the wellbore strengthening effect has been demonstrated using
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the constructed true triaxial cell. This facility allows application of three independent stresses to simulate far-field stresses and fracture containment compared to the commonly used small-scale triaxial cell. Furthermore, this facility is cost effective as a commercial large-scale true triaxial cell costs 0.5-1.5 million dollars. Regarding the experimental results,
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both experiments showed that WSM have plugged the whole fracture and achieved good pressure increment. Thus, a WSM pill with low injection rate may be used in field application.
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Moreover, in the experiments on the second sample, we observed the stress redistribution from two sets of fractures after plugging of WSM, which was not found in previous laboratory experiments or field testing to author’s knowledge. In the future, drilling mud with different types and concentration of WSM can be tested to quantify the wellbore strengthening effect. To better simulate field wellbore strengthening operation (if not considering the up-
5. Conclusions
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scaling effects), functions such as pore pressure and temperature control should be included.
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In this paper, wellbore strengthening experiments were performed on two Berea sandstone samples using a large-scale true triaxial cell. We used drill cuttings and Chevron LPM
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as WSM. The following conclusions can be drawn from this study: 1. Bi-wing fractures were generated in both samples due to the stress anisotropy provided by the true triaxial cell. The fractures were contained inside the rock sample by limiting the fluid injection rate under 1 mL/min.
2. For the first sample, the FBP was 999 psi. Three injection rates were applied After WSM plugging, an increasing jagged pressure trend was observed during the fracture propagation stage. The FROP was 2230.5 psi, which was 1231.5 psi higher than the FBP. 3. For the second sample, a higher horizontal stress ratio was applied. A constant in12
ACCEPTED MANUSCRIPT jection rate 0.5 mL/min was applied before and after WSM plugging. The FBP was 1651.2 psi and FROP is 2919.2 psi. Two set of fractures (two short fractures and two long fractures) were generated, which indicates the plugging of WSM can change stress distribution and the weakest point for fracture propagation. The mag-
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nified photographs show that the WSM plug the whole fracture. 4. The fracturing pressure profile from the first sample was compared to simulation results from a numerical model, which shows a very good match for the injection pressure. The proposed numerical model can be used to estimate the fracture geom-
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etry for wellbore strengthening design.
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Acknowledgements
The authors are grateful to the University of Tulsa Drilling Research Projects (TUDRP)
Abbreviations
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Formation breakdown pressure Fracture propagation pressure Fracture reopening pressure Joint industry project Lost preventive material Oil-based mud Particle size distribution Thermo-hydro-mechanical-chemical Water-based mud Wellbore strengthening materials
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FBP FPP FROP JIP LPM OBM PSD THMC WBM WSM
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member companies for their technical and financial support.
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Appendix A. Experimental Procedure
Due to the nature of the experiment (high pressure and large-scale), it is important to
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implement safe procedures. The following are brief procedures to conduct a fracturing experiment:
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(1). Prepare the rock sample. This step mainly includes drilling a hole in the sample and bonding the tubing to the rock sample.
(2). Load the rock sample into the cell. There are several steps involved in this step. First, we need to place spacers, hydraulic flat jacks and steel plates in the cell. The rock sample can be lifted by a hoist system from the ground into the true triaxial cell. Then, the cement
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mix is poured to fill the gaps between the rock sample and cubic grout surfaces to ensure full contact. Next, the top steel plate and the cell lid are placed on the top of the rock sample. Finally, we need to connect the tubing with the hydraulic pumps and Teledyne pump. (3). Run computer programs. There are two LabVIEW programs. The first program is
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for Teledyne pump control. Another LabVIEW program is used for monitoring and recording the pressure of hydraulic pumps. The parameters in the programs should be modified if there
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are any changes in a new experiment. (4). Apply three principal stresses using the hydraulic pumps. Manually pump three
hydraulic pumps to the desired pressures. Record the data using the LabVIEW program. (5). Inject the fluid into the rock sample using the Teledyne pump. If the Teledyne
pump is empty, it requires refill before injection. Once the pump is on, we need to monitor the pattern of the fluid injection pressure. During the early stage, there should be a pressure build up period. When the rock sample breaks down, a sharp pressure decline is expected. After significant pressure drop, the fluid pressure will keep almost constant (i.e., stable FPP). (6). Shut down the pumps and unload the cell. First, the injection pressure should be 22
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The above procedures can be repeated to refracture the rock. For wellbore strengthen-
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Fig. 1. Schematic of wellbore strengthening models. (a) Fracture propagation resistance. (b) Stress cage. (c) Fracture closure stress.
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Fig. 2. Components of the true triaxial cell. (a) Main cell frame. (b) Teledyne pump for fluid injection. (c) Hydraulic pumps for confining stress control. (d) Data acquisition system. (e) Cubic rock sample. (f) Schematic of the true triaxial cell.
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Fig. 3. Components of the triaxial cell. (a) Pore pressure and confining pressure intensifiers. (b) Data acquisition system. (c) Hydraulic pump. (d) Load frame. (e) Schematic of the triaxial cell.
Fig. 4. Wellbore strengthening materials. (a) Chevron loss prevention material (LPM). (b) Drill cuttings.
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Fig. 5. Fluid pressure response and injection rate for the first sample (black lines: fluid pressure; red dashed lines: injection rate). (a) Before WSM plugging. (b) After WSM plugging with a flow rate of 0.2 mL/min and 0.5 mL/min. (c) After WSM plugging with a flow rate of 1 mL/min. (WSM: wellbore strengthening materials).
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Fig. 6. (a) Split samples with bi-wing fractures for the first sample. The directions of maximum and minimum horizontal stresses were denoted on the rock surfaces. (b) Close view of the wellbore and fractures.
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Fig. 7. Fluid pressure response and injection rate for the second sample (black lines: fluid pressure; red dashed lines: injection rate). (a) Before WSM plugging. (b) After WSM plugging. (WSM: wellbore strengthening materials). Fig. 8. (a) Split samples with bi-wing fractures for the second sample. The directions of maximum and minimum horizontal stresses were denoted on the rock surface. (b) Close view of the wellbore and fractures.
Fig. 9. (a) Magnified view of a fracture with WSM for the second sample. (b) Higher magnified view of a fracture with WSM. (WSM: wellbore strengthening materials). Fig. 10. Comparison of fluid pressure of the first sample from simulation results and experimental results. 24
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Parameters
Value
Chebyshev polynomial term, m Young’s Modulus, E
50
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Fig. 11. Fracture mouth width of the first sample from simulation results.
1.53E6 psi 0.056
Wellbore radius, a
0.125 in.
Pore pressure, P
0 psi
Injection rate, Q
0.2 mL/min
Fluid viscosity, μ
300 cp
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Rock permeability, k
0.5 md
Rock porosity, ∅
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Fracture height, H
3.5 in.
Vertical stress, σ
580 psi
Maximum horizontal stress, σ
300 psi
Minimum horizontal stress, σ
110 psi
Wellbore inclination, I
0
Wellbore azimuth, A
0
Fracture toughness, K
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600 psi·√in.
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Table 1. Input parameters used in the simulation.
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Highlights
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Experimental investigation of fracture-based wellbore strengthening was conducted on a large-scale true triaxial cell. Fracture reopening pressures were higher than formation breakdown pressures. Results of induced and plugged fractures were shown.
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Stress redistribution was observed with plugging of wellbore strengthening materials.