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Geomechanical analysis on casing deformation in Longmaxi shale formation
Journal of Petroleum Science and Engineering 177 (2019) 724–733
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Geomechanical analysis on casing deformation in Longmaxi shale formation a,∗
a
a
a
b
Kai Dong , Naizhen Liu , Zhaowei Chen , Rui Huang , Jihui Ding , Geng Niu a b
b
T
China National Petroleum Corporation, China Texas A&M University, United States
ARTICLE INFO
ABSTRACT
Keywords: Casing shear Fault slip Longmaxi shale formation Sichuan basin Casing deformation Hydraulic fracturing
Casing deformation is the most significant problem while developing Longmaxi shale gas formation in Sichuan Basin, southwest China. In one of the operating acreages with 72 horizontal wells, 38 wells encountered casing deformation problems after several stages of hydraulic fracturing treatments. Tremendous lateral lengths were affected, among which some of them were treated with diversion technology during fracturing and some others were simply abandoned. Previous research explores this problem from perspectives of cementing, casing strength and etc. However, after combining all the data, we found that it is likely due to formation slip. In this research, we summarized all the casing deformation positions happened in the area of interest. We then project these positions into the ant-tracking plot. It is found that most of the deformed positions correspond to the fault positions in the ant-tracking plot. Further, we run caliper logs for some of the wells. From the images of the deformed positions, it can be inferred that the casing deformation is due to the formation shear. Based on what we found, we set up a model for fault slip potential. This model is based on Mohr-Coulomb (MC) failure criteria. We use this model to analyze the natural fractures observed from an FMI log. It is found that the increase of pore pressure from hydraulic fracturing jobs can cause natural fractures to slip. However, it cannot cause beddings to slip, which some of the previous research has suggested. The data and analysis in this research confirm that casing deformation in Longmaxi shale formation is caused by fault slip. Other reasons, like voids in cement bond, lithological layers, are not detrimental to this problem. In the end, we presented a method for continuing treatment when casing deformation happens. This method has been utilized in field, and significant downtime is reduced.
1. Introduction The commercial development of shale gas formations in Sichuan basin started from 2014. The typical development method is the same as that of other areas, horizontal drilling and multi-stage hydraulic fracturing. The casing deformation is detected when we pump down the bridge plug after finishing one stage of hydraulic fracturing. The bridge plug gets stuck because the diameter of the casing shrinks. If the casing deformation is not severe, bridge plugs of smaller diameter can get through, and the pre-designed engineering operations can resume. If it is severe, we need to consider other decisions. The problem of casing deformation is frequently encountered in the studied area. Significant research has been done on casing collapse. Peng et al. (2007) analyzed borehole casing failure in unconsolidated formations. Through numerical simulation, they found that most of the casing failures in their study were caused by casing buckling and fracturing. Zhang et al. (2008) studied the casing collapse for wells in the Gulf of Mexico. Their modeling reveals that casing failure was caused by non-
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uniform contact between salt and casing. This contact generates stresses which is larger than the yield strength of the casing. Daneshy (2005) studied casing failures during and after hydraulic fracturing. He concluded that casing can fail under tension across the fractured interval either by de-threading of the collars or by tensile failure at perforations. Furui et al. (2012) reviewed historical casing failure events in a highly compacting sandstone field and performed a comprehensive geomechanical analysis of various casing damage mechanisms. They found that large tensile and shear strains could develop within a thin, weakstrength layer, which causes casing failure. The research above shows casing failure can happen in almost every kind of reservoir, However, the casing deformation in Longmaxi shale formation has distinct differences with the cases described above for its shape and locations, which will be discussed later. During the past few years, dozens of research have been conducted on it. These studies proposed different reasons, including cement voids along the casing, decentralized casing, the effect of lithological layers, induced stress change and temperature change due to hydraulic fracturing and etc.
Corresponding author. E-mail address: [email protected] (K. Dong).
https://doi.org/10.1016/j.petrol.2019.02.068 Received 29 June 2018; Received in revised form 13 February 2019; Accepted 20 February 2019 Available online 22 February 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.
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Fig. 1. Structural map of Sichuan basin, modified from Fang Hao et al. (2008). There is a central uplift in the basin, where the area of interest in this paper is located, as denoted by the red rectangular. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
three reasons. They also proposed approaches for preventing casing shear, including using high-strength casing, increasing cement compliance and avoidance of slip planes. Their research is general and is not particularly for casing shear during multi-stage hydraulic fracturing. In general, casing deformation for shale gas wells in Longmaxi formation has been widely studied in the last few years. However, it is still a great challenge today because it happens all the time while developing shale gas reservoirs in southwest China. Unlike previous research, in this paper, we first demonstrate evidence that the casing deformation is more related to slips of pre-existing fractures and faults in the area of interest. Then, we analyzed the natural fractures distribution and the in-situ stress state of the studied area, based on which a geomechanical analysis on the fault slip potential was conducted. In the end, we provide innovative engineering solutions to continue the hydraulic fracturing treatments efficiently.
(Lian et al., 2015; Yan et al., 2017; Qian et al., 2015; Xi et al., 2018). However, as we have tried different engineering approaches in field as suggested by these previous researches, none of them work properly. These engineering solutions include installing sufficient numbers of centralizers while tripping down the production casing, rotating the casing string during the cementing process to avoid the cement voids forming or using warm fracturing fluids to minimize the pressure drop inside the voids. This problem is not widely seen in shale plays of North America per current literature review. However, it happens in Vaca Muerta shale formation of South America. Garcia et al. (2013) reported two cases. One was identified while completing the well, and the other one was identified before the initiation of well completion. The authors stated that these kinds of events occur often in their highly pressurized reservoirs. The reason for the casing deformation, as reported by the authors, is reactivations of weak places due to pumping fracturing fluids. Currently they do not have approaches for the prevention. Chen et al. (2017) identified the casing deformation that happened to shale gas wells of Longmaxi formation in Sichuan Basin as shear deformation by observing the caliper logs of the deformed wells. The caliper logs exhibit sharp drift along the casing. They think that faults and beddings are the internal cause for casing deformation, similar to the weak places as proposed by Garcia et al. (2013). When the pore pressure reaches a critical value due to pumping fracturing fluid into formations, the natural fractures slide and casing deformation happens. They proposed three solutions to prevent casing deformation, including installing packers at the casing position where natural fracture exists, using compliant cement and deploying different fracturing techniques to avoid repeated casing loading. These solutions need to be further evaluated in field. Dusseault et al. (2001) discussed casing shear mechanisms in general reservoir development. They think that casing shear is caused by rock shear. Rock shear is caused by changes in stress and pressure, which can be induced by hydrocarbon recovery activities, like depletion, injection, and heating. They illustrated field examples for these
2. Current situation of casing deformation in the area of interest The Sichuan Basin locates in southwest China and has an area of about 230,000 km2. The basin is tectonically bounded by 4 fold belts and 1 uplift around it, as shown in Fig. 1. Conventional natural gas from carbonate formations and sandstone formations has been developed for decades in this basin. Until recent years, the unconventional gas has been discovered and being commercially developed. The Lower Silurian Longmaxi shale formation is a newly emerged shale gas play being commercially developed. The depth of this formation ranges from 5,000 ft to 13,000 ft across Sichuan basin, with deep shelf depositional facies. It has an average formation thickness of 150 ft, and an average porosity of 6%. Natural fractures exist as observed from downhole cores and FMI logs in multiple wells, which provide potential gas flow paths to hydraulically created fractures. The primary brittle mineral is quartz, ranging from 43% to 74%. The formation below Longmaxi shale is Wufeng formation, which is carbonate in its upper part and shale in its lower part. It also contains free gas but is not the main pay zone. Below Wufeng is Baota formation. 725
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Fig. 2. Lighological units and geophysical logs from a pilot well in the area of interest. The Longmaxi formation is the main pay zone. Significant gas bubbles were observed when downhole cores were taken out and put into water at the well site. Below Longmaxi formation is the Wufeng formation. Minor gas bubbles were observed. Even below Wufeng formation is the Baota formation. We did not observe any gas bubbles from downhole cores.
Fig. 3. These three plots show when and how we detect casing deformation. We identify the deformed position when the bridge plug gets stuck. Based on our operations data here, it can be any place along the wellbore. Also, it may happen after any stages of fracturing treatments.
Fig. 3. (continued)
outer diameter of commonly used bridge plugs is 100 mm in this area. During pumping the bridge plug down, if there is casing deformation, the bridge plug gets stuck. Fig. 3 shows the image of this situation. In Fig. 3a, the bridge plug is set, and three clusters are perforated. The wellbore is ready for hydraulic fracturing. In Fig. 3b, hydraulic fracturing is executed. Somehow casing deformation happens. In Fig. 3c, after a hydraulic fracturing job, we pump down another set of bridge
It mainly consists of carbonate minerals and contains little gas. Fig. 2 shows the lithological units, geophysical logs, and elemental capture spectroscopy data. The casing deformation is detected when pumping the bridge plug into the wellbore after finishing one stage of hydraulic fracturing treatment. The casing inner diameter is 4.5 inches (114.3 mm). The 726
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data. From Fig. 5, we can see that most of the deformed positions agree with fault positions very well. 3. Shape of casing deformation To identify the mechanism of casing deformation in this area, we need to know the shape of it. Caliper logs were used for the identification on some of the deformed wells. One of the logging results is shown in Fig. 6. The wellbore is measured by the use of a 24-arm caliper logging tool. The measured data were processed by logging specialized software. From the offset positions in the figure, we can see that the casing was probably undergone formation shear movement. Caliper logs of our other deformed wells exhibit the same shape. We also run coiled tubing with lead impression blocks into those deformed wells. During the trip into the well, this tool got obstructed at the deformed position and stopped. We then continue running the coiled tubing so that a weight can be applied to the tool. Typically, a 7000 lbs weight was applied to the lead impression blocks. The soft lead face is imprinted with the impact. The indentation can be interpreted to provide an indication as to the cause and type of obstruction within the well. One of the typical lead impressions is shown in Fig. 7. In this figure, the arc shape of the impression indicates that the casing deformed in the radial direction. The two sides of the deformed casing move to opposite directions, and the movement is around 21 mm. It indicates the same shape of the deformed casing as that of obtained from the caliper log. Both the caliper log measurements and the shape of the lead impression block suggest that the casing deformation is more likely due to formation shear. For the following analysis, we focus on the formation shear.
Fig. 3. (continued)
plug and perforation guns to the pre-designed position through wireline. However, because the casing diameter becomes smaller than the outer diameter of the bridge plug, the plug gets stuck at the deformed position. During field operations, we also notice that casing deformation can become severer as time goes by. During pumping a bridge plug, it got obstructed at position 1. After around 12 h, we pumped the same bridge plug, it happened 16 ft ahead of position 1, as noted by position 2. Then we changed a bridge plug with a smaller diameter. It passed the position 2 but got obstructed 7 ft ahead of the position 1. This is illustrated in Fig. 4. The casing deformation causes significant loss to the reservoir development. On one aspect, it brings downtime. Usually, when the bridge plug gets stuck, we pull it out and change another bridge plug with a smaller outer diameter. Sometimes, the wireline breaks when we pull it out. And we use coiled tubing to fish the guns and the plug. Significant non-productive time is caused. This is not the most important issue. If the casing deformation is severe enough, we cannot perforate the lateral between the deformed position and the last treated stage. This leaves an unstimulated lateral, which directly affects production. Currently, we have 72 hydraulic fractured horizontal wells that are in production. Among them, casing deformation happened to 38 wells. For the affected laterals, some of them were treated using diversion techniques, while some of them were simply abandoned. We projected the deformed positions in the ant-tracking plot, as shown by pink circles in Fig. 5. This plot is generated based on local seismic data, which were obtained by a 3D reflection seismic survey with a sampling interval of 2 ms and record length of 4s. The generation of ant-tracking plot is through the use of commercial software, which can incorporate seismic data and do further calculations. The algorithm inside first calculates the variance attribute of the seismic data to enhance the spatial discontinuities along the reflection layers. Then it improves the fault attributes by suppressing noise and remains of non-faulting events. These attributes map different seismic objects with high quality including fault surfaces (Randen et al., 2001). The advantage of this method is that the fault extraction can be automatically achieved from seismic
4. Model for fault slip One of the key features of unconventional reservoirs is the existence of natural fractures. These preexisting natural fractures and faults can serve as fluid conduits during hydraulic fracturing. Yang and Zoback (2014) studied microseismic events distributions for a well pad of Bakken formation. In their case, when fracturing Bakken formation, significant amounts of events were recorded in Mission Canyon formation, which is around 1000 ft above Bakken formation. Also, when fracturing one well for a stage close to the toe, microseismic events were recorded along the adjacent well close to the heel. Their further analysis confirmed that it is preexisting natural fractures and faults that serve as flow pathways during fracturing. In his work, he also set up a geomechanical model for the area of interest. Through his model, he analyzed the fault slip potential due to pore pressure elevation. Fisher et al. (2002) described a large hydraulic fracture diagnostic project in the Barnett Shale. This diagnostic project integrated tiltmeter and microseismic mapping. In this project, they observed a hydraulic fracturing job in one well killing other offset wells in Barnett Shale. It proves that a fracture network instead of only bi-wing fractures is
Fig. 4. Casing deformation becomes severer with time. The left figure shows the bridge plug got obstructed at an earlier time. The right figure shows it got obstructed at a later time, and the position is usually within 30 ft (a piece of casing length) ahead of the first position. 727
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Fig. 5. Ant-tracking plot with horizontal wells projected. The black color represents fault or pre-existing natural fractures. The pink circles along the laterals mark the casing deformation positions. The red hexagon shows the location of the pilot well with FMI log. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 6. Caliper log for a well with casing deformation. This measurement is from 24-arm caliper tool. There are 9 deformed locations along the 886-ft log interval. The maximum offset distance is 17 mm.
created during the hydraulic fracturing job. The development of the fracture network is highly variable. Unless we have a detailed fracture distribution for the formation, we cannot predict how fracturing fluids go and how the fracture network develops. This detailed fracture distribution for the whole formation is not quite possible with current technology. For the shale gas reservoir in the area of interest, tremendous amounts of preexisting natural fractures and faults also exist, which are identified from seismic data and formation micro-imager (FMI) log
data. The advantage of FMI log is that it can identify different types of fractures. The position of the pilot well in this study is shown in Fig. 5. The logged interval is 984 ft. From the FMI log, we can identify beddings, conductive fractures, and resistive fractures. Beddings are identified through their orientations, angles, and textures. Conductive and resistive fractures are identified through the resistivity. Fig. 8 shows the stereonet plot for these fractures. The dip angle of beddings is small, around 6°. The strike of beddings is around 135°. Since the beddings are almost horizontally 728
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Fig. 7. Lead impression block of a deformed position. The outer diameter of the lead block is 90 mm. The impression on the surface has a width of 11–12 mm. It is close to the wall thickness of the casing, which is 12.7 mm.
5. Stress state of the studied area A series of geophysical logs were also run for the pilot well, which are used to study the stress state of this area. The overburden stress for Longmaxi formation is calculated through the density log. To get the minimum horizontal stress, a diagnostic fracture test was conducted. From the pressure curve after shut-in, we can identify the formation closure pressure and pore pressure. Formation closure pressure is treated as minimum horizontal stress. From the FMI image log, we see clear drilling-induced tensile fractures (DITFs) for the depth of interest, which is used to constrain the range of the maximum horizontal stress. The friction coefficient is assumed as 0.67 (Zoback and Townend, 2001). The in-situ stress state for the depth of interest is presented by a stress diagram shown in Fig. 9. The parameters used to generate this diagram is shown in Table 2. In Fig. 9, the outer bound by the black line is from frictional strength equilibrium. The blue line represents the condition of DITFs. The spanned values by the green line are the ranges of Shmax given all the conditions above, which is 12,257.3–14225.6 psi. It is strike-slip faulting regime. The gradient for maximum horizontal stress is 1.31–1.52. Fig. 8. Stereonet plot illustrating the natural fractures measured through FMI log of the pilot well. The black, red and blue colors represent beddings, conductive fractures, and resistive fractures respectively. The algorithms for this plot are found in Allmendinger et al. (2012), Cardozo N. and Allmendinger R.W. (2013).(For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
6. Fault slip potential analysis Fault can slip when there is pore pressure perturbation. Healy et al. (1968) discussed the triggered earthquakes in Denver due to longtime wastewater injection. They believed that the mechanism by which fluid injection triggered the earthquakes is the reduction of frictional resistance to faulting, a reduction which occurs with an increase in pore pressure. Walsh and Zoback (2016) presented a framework for calculating the conditional probability of fault slip from pore pressure perturbation by modeling Mohr-Coulomb slip. The results can be used to assess the probability of induced slip on a known fault from a given injection-related pore pressure increase. Their approach provides a rigorous quantification of mapped fault slip potential, which incorporates uncertainties in relevant parameters. During a hydraulic fracturing treatment stage in the area of interest, normally around 12,000 barrels of slick water is pumped into formation within 2.5 h. Casing deformation usually happens after several stages of fracturing. That is around 60,000 barrels of fluid injection (if after 5 stages, which is common). If there are no natural fractures, the slick water just creates the main fracture and slowly leaks off into the formation. However, natural fractures are widespread in this shale formation, and we cannot predict where the fracturing fluids go. It may go into other layers, or flow along the wellbore through a preexisting conduit, as described by Yang and Zoback (2014). Nevertheless, there is
Table 1 FMI log measurements statistics. Pilot Well
Numbers detected
Dip angle, ˚
Strike, ˚
Beddings Conductive fractures Resistive fractures
449 17 20
6 6.1–88.4 15.6–76.2
Around 135 Majority around 132 Majority around 170
parallel, they are unlikely to slip when there are pore pressure perturbations. The further analysis below shows our speculation. The dip angles for conductive fractures vary from 6.1˚–88.4°. We may speculate that higher dip angles result in easy fault slips. The dip angles for resistive fractures vary from 15.6˚-76.2°. The statistics of the FMI log measurements for the pilot well is summarized in Table 1. 729
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Fig. 9. In-situ stress state at 9260 ft constrained by the frictional strength equilibrium and observed drilling induced tensile fractures through the FMI log. The green line represents the range of Shmax, and it lies in the strike-slip faulting regime. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 10. 2D stress state. σ1 is equivalent to the maximum horizontal stress and σ3 is equivalent to the minimum horizontal stress. β is the dip angle. σn is normal stress that is applied to the fault and τ is shear stress along the fault.
Table 2 Geomechanical parameters for the stress diagram. Parameters
Values
Depth Pore Pressure Pp Shmin Sv ΔP between mud pressure and pore pressure Thermal Expansion Tensile strength, T0 UCS, C0 Young's modulus, E Poisson's ratio
9350 ft 5668 psi 8105.5 psi 10,541.5 psi 607.3 psi 2.4 × 10−6 ˚C−1 negligible 17,400 psi 4.26 × 106 psi 0.11
which are 9248.4 psi, 6633.6 psi and 4708.3 psi respectively. σ1 and σ3 are calculated by subtracting pore pressure from Shmax and Shmin. Substituting these values into Eq. (2) and Eq. (3), we can get 868-psi shear stress, and 2255-psi effective normal stress. If we do the calculation for all fractures and show them in a scatter plot, as shown by Fig. 11, we can see the stress data of these fractures form a circle. The red, blue and black dots are for conductive fractures, resistive fractures and beddings respectively. The pink line is the fault slip criteria. We can see that all the black dots are grouped together, while the red and blue dots are distributed as a semicircle. This is because all beddings have similar dip angles and the dip angles for other fractures are varied. At the original state, all fractures are at their equilibrium state, as shown by Fig. 11a. When the pore pressure increases 500 psi across this logged interval, three fractures are likely to slip with one conductive fracture and two resistive fractures, as shown by Fig. 11b. There is a likelihood that casing deformation can happen. The conductive fracture is identified as 8796.6 ft depth with 110.8° strike and 53.2° dip angle. The two resistive fractures are identified as 9332.6 ft depth with 4.6° strike and 68.2° dip angle, 9333.4 ft with 358.2° strike and 68.8° dip angle. If somehow, there are no flow conduits to that fracture, and the hydraulic fracturing jobs cannot increase the pore pressure around that fracture, it will not slip. When the hydraulic fracturing jobs increase the pore pressure around some fractures by 2000 psi (Fig. 11c), these fractures slip and the likelihood for casing deformation is larger. It is very difficult for beddings to slip because the pore pressure around the beddings must increase by 3200 psi (Fig. 11d). This is unlikely to happen because fracturing fluids leak off to a natural fracture network. Therefore, we think previously published studies attributed casing deformation to movements of lithological layers are not correct. If we do the same calculation for an area of interest, we can identify how much pore pressure elevations are needed to induce fault slips areally. Fig. 12 shows the calculation results for some of our producing area (upper right part of Fig. 5). The left figure is the ant-tracking plot with horizontal wells and deformed locations projected. In the right figure, the faults are extracted from the original data. Each fault has its own depth, azimuth, and dip angle. The color on each fault represents how much pore pressure elevation is needed to induce its slip. Around 1,000 psi of pore pressure elevation is needed for some faults, and most of the deformed positions are close to those faults.
Sources Mini-frac Mini-frac Density log Mud density Lab experiments Lab experiments Lab experiments
a possibility that the slick water elevates the pore pressure near a fault. When the pore pressure increases, the effective overburden stress decreases, and the fault may slip. Below we provide a detailed analysis. The commonly used slip criteria for a fault is the Mohr-Coulomb (MC) criteria. It describes a relationship between effective shear stress and effective normal stress. The effective stress is defined by Terzaghi's law, as shown by Eq. (1).
=
pp
(1)
where σ′ is effective stress, σ is stress and pp is pore pressure. In this study, we consider the fault slip in a 2-dimensional domain. The problem is simplified as the radial extension stress state, as shown by Fig. 10. Considering the state equilibrium under the two stresses, we can derive the shear stress and normal stress applied to the fault, as shown by Eq. (2) and Eq. (3).
= 0.5( n
= 0.5(
3)sin
1 1
+
3)
(2)
2
+ 0.5(
1
3)cos
2
(3)
For every fracture that is detected by an FMI log, it has a dip angle, depth, and a fracture azimuth. We can calculate the effective normal stress and shear stress which are applied on it. For example, one of the fractures in Pilot Well-A is at the depth of 8407.6 ft and has a dip angle of 69.2°. The maximum horizontal stress, minimum horizontal stress, and pore pressure are calculated by their gradients time the depth, 730
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Fig. 11. Stability analysis of the fault planes in the Longmaxi formation. The red, blue and black dots are for conductive fractures, resistive fractures and beddings respectively. Four case scenarios are analyzed, (a) original state with no pore pressure perturbation; (b) a post-stimulation scenario from original state with 500 psi pore pressure increase; (c) a post-stimulation scenario from original state with 2000 psi pore pressure increase; (d) a post-stimulation scenario from original state with 3200 psi pore pressure increase. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 12. a. Ant-Tracking plot with horizontal wells projected. The deformed positions are marked in the horizontal wells. b. Faults are extracted and faults slip potential is analyzed. The unit of color bar is psi. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
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plug and perforate. It does not affect the operation. This is the bestcase scenario. 2. If the smaller bridge plug cannot pass through the deformed position either, we pump down a dissolvable dummy plug with perforation guns to the predesigned position and perforate through a wireline unit. Before hydraulic fracturing, diverters are needed to plug the previous stage of fractures. The diameter of the dummy plug is slightly larger than the perforation guns and has a ring outside for pumping. If the dummy plug gets stuck during the pumping, we pump some salt water into the well to dissolve this plug. 3. If the dummy plug cannot get through the deformed position either, we run coiled tubing with perforation guns of smaller diameter to the designed position and perforate. 4. If smaller perforation guns cannot pass through the deformed position, we have to abandon the lateral between deformed position and last stage of fracturing. This is the worst-case scenario.
Table 3 Casing comparison in the area of interest.
Grade Outer diameter Inner diameter Wall thickness Internal yield pressure Collapse strength
Commonly used casing
Higher grade casing
Q125 5 1/2 inches 4 1/2 inches 12.7 mm 19,880 psi 20,663 psi
Q125 5.7 inches 4 1/2 inches 15.2 mm 19,880 psi 24,679 psi
7. Discussions Although casing deformation happens frequently for Longmaxi shale formation in Sichuan basin, rare cases were reported for shale formations across North America. One of the possible reasons is that the difference between maximum horizontal stress and minimum horizontal stress is large (approximate 1800–2000 psi, internal data). This can cause the Mohr circle to be larger and intersect with the fault slip criteria. At the current stage, we do not have comparisons with data of North America, but it deserves further research. The pre-existing fractures and faults can act flow conduits for fracturing fluids, as we reviewed earlier. Micro annulus in the cement sheath can also be a flow conduit if the cementing job is poor. Especially, during multi-stage hydraulic fracturing treatments, the casing undergoes repeat loading and unloading processes, which can cause the micro-annulus increase remarkably (Chen et al., 2017). Another important aspect is the scale of the slipping natural fractures. In this research, we assume each slipped natural fracture can cause casing deformation, but we believe its scale plays a role. Further research is needed on this perspective. Previous research also suggested utilizing high-grade casing or compliant cement (Dusseault et al., 2001). We had field trial for both two methods. We had 7 wells completed with high-grade casing. The wall thickness is 15.2 mm, which is 2.5 mm larger than the previouslyused casing. Among those 7 wells, 5 wells encountered casing deformation. A comparison between commonly used casing and the highgrade casing is shown in Table 3 below. From the table, we can see that the collapse strength is 20% larger than the previously used casing. However, the casing still deformed. The compliant cement we used is a type of foam cement. Compared with conventional cement, nitrogen is mixed in it so that gas voids can increase its final strength. It is widely used to cement wells in highstress environments (Crandall et al., 2014). We had two wells cemented with compliant cement. The casing of both the two wells deformed during multi-stage hydraulic fracturing. Due to limited amounts of tests, further field evaluation for this type of cement is needed.
The successful application of this operation mode in field proves that it is an effective method to handle casing deformation during hydraulic fracturing treatments. 9. Suggestions for preventing casing deformation Based on the analysis in this study, the only method to prevent casing deformation is to control the pore pressure elevation. This requires a controlled hydraulic fracturing scale. By doing this, future hydrocarbon production can be affected. If there are flow pathways to a critically stressed fault during fracturing, even small volume of fracturing fluids can cause critically-stressed faults to slip. In the meanwhile, as we can identify open fractures from FMI logs, we can have the portion of the laterals that penetrate the faults logged. Then we can identify the open fractures crossing the wellbore. By doing this, we can take preventive engineering actions in advance. 10. Conclusions In this study, we studied the casing deformation based on field measurements and a geomechanical analysis. The positions of casing deformation for 72 horizontal wells in Longmaxi shale gas formation are summarized and projected into the Ant-Tracking plot. The fault slip potential is analyzed for fractures from FMI log observations. Based on the observations and analysis, we can conclude this research as follows. 1. The caliper log measurements and lead print impression indicate that casing deformation is likely due to faults slip. 2. Pore pressure elevation due to hydraulic fracturing can cause fault slip. The deformed locations from our wells are close to the faults which are easier to slip. 3. Currently, there is no effective method for casing deformation prevention. However, a new approach for overcoming the operational difficulty is presented in this paper, which has been applied with success in field.
8. Innovative methods for stimulating deformed laterals The casing deformation brings great difficulty for pumping the bridge plug to the designated position. To stimulate the lateral between deformed position and last stage of fractures, we need to run the perforation gun through the deformed position. Previous operation method utilizes coiled tubing for the perforation operation. This takes much more time compared with wireline pumping. Our recent experience features a dissolvable dummy bridge plug for wireline pumping, which can save a coiled tubing run. Generally, there are four scenarios when casing deformation happens.
Acknowledgment The authors thank Great Wall Drilling Company (a subsidiary of China National Petroleum Corporation), for providing financial support, the datasets, and core samples for this study. Appendix A. Supplementary data
1. If the casing deformation is not severe and a bridge plug of smaller diameter can get through, we pump this bridge plug with perforation guns to the designed position through a wireline unit, set the
Supplementary data to this article can be found online at https:// doi.org/10.1016/j.petrol.2019.02.068. 732
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Nomenclature σ σ′ τ pp β Sv Shmin Shmax
Garcia, M.N., Sorenson, F., Bonapace, J.C., et al., 2013. Vaca muerta shale reservoir characterization and description: the starting point for development of a shale play with very good possibilities for a successful project. In: Paper presented at the Unconventional Resources Technology Conference, Denver, Colorado, USA. Unconventional Resources Technology Conference. Healy, J.H., Rubey, W.W., Griggs, D.T., et al., 1968. The denver earthquakes. Science 161 (3848), 1301–1310. https://doi.org/10.1126/science.161.3848.1301. Lian, Z., Yu, H., Lin, T., et al., 2015. A study on casing deformation failure during multistage hydraulic fracturing for the stimulated reservoir volume of horizontal shale wells. J. Nat. Gas Sci. Eng. 23, 538–546. https://doi.org/10.1016/j.jngse.2015.02. 028. Peng, S., Fu, J., Zhang, J., 2007. Borehole casing failure analysis in unconsolidated formations: A case study. J. Petrol. Sci. Eng. 59 (3), 226–238. https://doi.org/10.1016/j. petrol.2007.04.010. Qian, B., Yin, C., Li, Y., et al., 2015. Diagnostics of casing deformation in multi-stage hydraulic fracturing stimulation in lower silurian marine shale play in southwestern china. In: Paper presented at the Unconventional Resources Technology Conference, San Antonio, Texas, USA. Unconventional Resources Technology Conference, https:// doi.org/10.15530/URTEC-2015-2174637. Randen, T., Pedersen, S.I., Sønneland, L., 2001. Automatic extraction of fault surfaces from three-dimensional seismic data. In: Paper presented at the 2001 SEG Annual Meeting, vol. 4 Society of Exploration Geophysicists, San Antonio, Texas. Walsh, F.R., Zoback, M.D., 2016. Probabilistic assessment of potential fault slip related to injection-induced earthquakes: application to north-central oklahoma, USA. Geology 44 (12), 991–994. https://doi.org/10.1130/g38275.1. Xi, Y., Li, J., Liu, G., et al., 2018. Numerical investigation for different casing deformation reasons in weiyuan-changning shale gas field during multistage hydraulic fracturing. J. Petrol. Sci. Eng. 163, 691–702. https://doi.org/10.1016/j.petrol.2017.11.020. Yan, W., Zou, L., Li, H., et al., 2017. Investigation of casing deformation during hydraulic fracturing in high Geo-Stress Shale Gas Play. J. Petrol. Sci. Eng. 150, 22–29. https:// doi.org/10.1016/j.petrol.2016.11.007. Yang, Y., Zoback, M.D., 2014. The role of preexisting fractures and faults during multistage hydraulic fracturing in the bakken formation. Interpretation 2 (3), SG25–SG39. https://doi.org/10.1190/int-2013-0158.1. Zhang, J., Standifird, W.B., Lenamond, C., 2008. Casing ultradeep, ultralong salt sections in deep water: a case study for failure diagnosis and risk mitigation in record-depth well. In: Paper presented at the SPE Annual Technical Conference and Exhibition, vol. 24 Society of Petroleum Engineers, Denver, Colorado, USA. https://doi.org/10.2118/ 114273-MS. Zoback, M.D., Townend, J., 2001. Implications of hydrostatic pore pressures and high crustal strength for the deformation of intraplate lithosphere. Tectonophysics 336 (1), 19–30. https://doi.org/10.1016/S0040-1951(01)00091-9.
normal stress effective normal stress shear stress pore pressure dip angle overburden stress minimum horizontal stress maximum horizontal stress
References Allmendinger, R.W., Cardozo, N., Fisher, D., 2012. Structural geology algorithms; Vectors and tensors in structural geology. Cambridge University Press. Cardozo, N., Allmendinger, R.W., 2013. Spherical projections with OSXStereonet. Comput. Geosci. 51, 193–205. https://doi.org/10.1016/j.cageo.2012.07.021. Chen, Z., Shi, L., Xiang, D., 2017. Mechanism of casing deformation in the Changning–Weiyuan National shale gas demonstration area and countermeasures. Nat. Gas. Ind. B 4 (1), 1–6. https://doi.org/10.1016/j.ngib.2017.07.001. Crandall, D., Gill, M., Moore, J., et al., 2014. Foamed Cement Analysis with Computed Tomography. In: 2014 4th Joint US-European Fluids Engineering Division Summer Meeting, Original edition. ASME, Chicago (ISBN). Daneshy, A.A., 2005. Impact of off-balance fracturing on borehole stability and casing failure. In: Paper presented at the SPE Western Regional Meeting, vol. 9 Society of Petroleum Engineers, Irvine, California. https://doi.org/10.2118/93620-MS. Dusseault, M.B., Bruno, M.S., Barrera, J., 2001. Casing shear: Causes, cases. Cures. https://doi.org/10.2118/72060-PA. Fang Hao, T.G., Zhu, Yangming, Cai, Xunyu, Zou, Huayao, Li, Pingping, 2008. Evidence for multiple stages of oil cracking and thermochemical sulfate reduction in the puguang gas field, Sichuan Basin, China. AAPG (Am. Assoc. Pet. Geol.) Bull. 92 (5), 611–637. https://doi.org/10.1306/01210807090. Fisher, M.K., Wright, C.A., Davidson, B.M., et al., 2002. Integrating Fracture Mapping Technologies to Optimize Stimulations in the Barnett Shale. Society of Petroleum Engineershttps://doi.org/10.2118/77441-MS. Furui, K., Fuh, G.-F., Morita, N., 2012. Casing- and screen-failure analysis in highly compacting sandstone fields. SPE Drill. Complet. 27 (02), 241–252. https://doi.org/ 10.2118/146231-PA.
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Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
Geomechanical analysis on casing deformation in Longmaxi shale formation a,∗
a
a
a
b
Kai Dong , Naizhen Liu , Zhaowei Chen , Rui Huang , Jihui Ding , Geng Niu a b
b
T
China National Petroleum Corporation, China Texas A&M University, United States
ARTICLE INFO
ABSTRACT
Keywords: Casing shear Fault slip Longmaxi shale formation Sichuan basin Casing deformation Hydraulic fracturing
Casing deformation is the most significant problem while developing Longmaxi shale gas formation in Sichuan Basin, southwest China. In one of the operating acreages with 72 horizontal wells, 38 wells encountered casing deformation problems after several stages of hydraulic fracturing treatments. Tremendous lateral lengths were affected, among which some of them were treated with diversion technology during fracturing and some others were simply abandoned. Previous research explores this problem from perspectives of cementing, casing strength and etc. However, after combining all the data, we found that it is likely due to formation slip. In this research, we summarized all the casing deformation positions happened in the area of interest. We then project these positions into the ant-tracking plot. It is found that most of the deformed positions correspond to the fault positions in the ant-tracking plot. Further, we run caliper logs for some of the wells. From the images of the deformed positions, it can be inferred that the casing deformation is due to the formation shear. Based on what we found, we set up a model for fault slip potential. This model is based on Mohr-Coulomb (MC) failure criteria. We use this model to analyze the natural fractures observed from an FMI log. It is found that the increase of pore pressure from hydraulic fracturing jobs can cause natural fractures to slip. However, it cannot cause beddings to slip, which some of the previous research has suggested. The data and analysis in this research confirm that casing deformation in Longmaxi shale formation is caused by fault slip. Other reasons, like voids in cement bond, lithological layers, are not detrimental to this problem. In the end, we presented a method for continuing treatment when casing deformation happens. This method has been utilized in field, and significant downtime is reduced.
1. Introduction The commercial development of shale gas formations in Sichuan basin started from 2014. The typical development method is the same as that of other areas, horizontal drilling and multi-stage hydraulic fracturing. The casing deformation is detected when we pump down the bridge plug after finishing one stage of hydraulic fracturing. The bridge plug gets stuck because the diameter of the casing shrinks. If the casing deformation is not severe, bridge plugs of smaller diameter can get through, and the pre-designed engineering operations can resume. If it is severe, we need to consider other decisions. The problem of casing deformation is frequently encountered in the studied area. Significant research has been done on casing collapse. Peng et al. (2007) analyzed borehole casing failure in unconsolidated formations. Through numerical simulation, they found that most of the casing failures in their study were caused by casing buckling and fracturing. Zhang et al. (2008) studied the casing collapse for wells in the Gulf of Mexico. Their modeling reveals that casing failure was caused by non-
∗
uniform contact between salt and casing. This contact generates stresses which is larger than the yield strength of the casing. Daneshy (2005) studied casing failures during and after hydraulic fracturing. He concluded that casing can fail under tension across the fractured interval either by de-threading of the collars or by tensile failure at perforations. Furui et al. (2012) reviewed historical casing failure events in a highly compacting sandstone field and performed a comprehensive geomechanical analysis of various casing damage mechanisms. They found that large tensile and shear strains could develop within a thin, weakstrength layer, which causes casing failure. The research above shows casing failure can happen in almost every kind of reservoir, However, the casing deformation in Longmaxi shale formation has distinct differences with the cases described above for its shape and locations, which will be discussed later. During the past few years, dozens of research have been conducted on it. These studies proposed different reasons, including cement voids along the casing, decentralized casing, the effect of lithological layers, induced stress change and temperature change due to hydraulic fracturing and etc.
Corresponding author. E-mail address: [email protected] (K. Dong).
https://doi.org/10.1016/j.petrol.2019.02.068 Received 29 June 2018; Received in revised form 13 February 2019; Accepted 20 February 2019 Available online 22 February 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.
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Fig. 1. Structural map of Sichuan basin, modified from Fang Hao et al. (2008). There is a central uplift in the basin, where the area of interest in this paper is located, as denoted by the red rectangular. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
three reasons. They also proposed approaches for preventing casing shear, including using high-strength casing, increasing cement compliance and avoidance of slip planes. Their research is general and is not particularly for casing shear during multi-stage hydraulic fracturing. In general, casing deformation for shale gas wells in Longmaxi formation has been widely studied in the last few years. However, it is still a great challenge today because it happens all the time while developing shale gas reservoirs in southwest China. Unlike previous research, in this paper, we first demonstrate evidence that the casing deformation is more related to slips of pre-existing fractures and faults in the area of interest. Then, we analyzed the natural fractures distribution and the in-situ stress state of the studied area, based on which a geomechanical analysis on the fault slip potential was conducted. In the end, we provide innovative engineering solutions to continue the hydraulic fracturing treatments efficiently.
(Lian et al., 2015; Yan et al., 2017; Qian et al., 2015; Xi et al., 2018). However, as we have tried different engineering approaches in field as suggested by these previous researches, none of them work properly. These engineering solutions include installing sufficient numbers of centralizers while tripping down the production casing, rotating the casing string during the cementing process to avoid the cement voids forming or using warm fracturing fluids to minimize the pressure drop inside the voids. This problem is not widely seen in shale plays of North America per current literature review. However, it happens in Vaca Muerta shale formation of South America. Garcia et al. (2013) reported two cases. One was identified while completing the well, and the other one was identified before the initiation of well completion. The authors stated that these kinds of events occur often in their highly pressurized reservoirs. The reason for the casing deformation, as reported by the authors, is reactivations of weak places due to pumping fracturing fluids. Currently they do not have approaches for the prevention. Chen et al. (2017) identified the casing deformation that happened to shale gas wells of Longmaxi formation in Sichuan Basin as shear deformation by observing the caliper logs of the deformed wells. The caliper logs exhibit sharp drift along the casing. They think that faults and beddings are the internal cause for casing deformation, similar to the weak places as proposed by Garcia et al. (2013). When the pore pressure reaches a critical value due to pumping fracturing fluid into formations, the natural fractures slide and casing deformation happens. They proposed three solutions to prevent casing deformation, including installing packers at the casing position where natural fracture exists, using compliant cement and deploying different fracturing techniques to avoid repeated casing loading. These solutions need to be further evaluated in field. Dusseault et al. (2001) discussed casing shear mechanisms in general reservoir development. They think that casing shear is caused by rock shear. Rock shear is caused by changes in stress and pressure, which can be induced by hydrocarbon recovery activities, like depletion, injection, and heating. They illustrated field examples for these
2. Current situation of casing deformation in the area of interest The Sichuan Basin locates in southwest China and has an area of about 230,000 km2. The basin is tectonically bounded by 4 fold belts and 1 uplift around it, as shown in Fig. 1. Conventional natural gas from carbonate formations and sandstone formations has been developed for decades in this basin. Until recent years, the unconventional gas has been discovered and being commercially developed. The Lower Silurian Longmaxi shale formation is a newly emerged shale gas play being commercially developed. The depth of this formation ranges from 5,000 ft to 13,000 ft across Sichuan basin, with deep shelf depositional facies. It has an average formation thickness of 150 ft, and an average porosity of 6%. Natural fractures exist as observed from downhole cores and FMI logs in multiple wells, which provide potential gas flow paths to hydraulically created fractures. The primary brittle mineral is quartz, ranging from 43% to 74%. The formation below Longmaxi shale is Wufeng formation, which is carbonate in its upper part and shale in its lower part. It also contains free gas but is not the main pay zone. Below Wufeng is Baota formation. 725
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Fig. 2. Lighological units and geophysical logs from a pilot well in the area of interest. The Longmaxi formation is the main pay zone. Significant gas bubbles were observed when downhole cores were taken out and put into water at the well site. Below Longmaxi formation is the Wufeng formation. Minor gas bubbles were observed. Even below Wufeng formation is the Baota formation. We did not observe any gas bubbles from downhole cores.
Fig. 3. These three plots show when and how we detect casing deformation. We identify the deformed position when the bridge plug gets stuck. Based on our operations data here, it can be any place along the wellbore. Also, it may happen after any stages of fracturing treatments.
Fig. 3. (continued)
outer diameter of commonly used bridge plugs is 100 mm in this area. During pumping the bridge plug down, if there is casing deformation, the bridge plug gets stuck. Fig. 3 shows the image of this situation. In Fig. 3a, the bridge plug is set, and three clusters are perforated. The wellbore is ready for hydraulic fracturing. In Fig. 3b, hydraulic fracturing is executed. Somehow casing deformation happens. In Fig. 3c, after a hydraulic fracturing job, we pump down another set of bridge
It mainly consists of carbonate minerals and contains little gas. Fig. 2 shows the lithological units, geophysical logs, and elemental capture spectroscopy data. The casing deformation is detected when pumping the bridge plug into the wellbore after finishing one stage of hydraulic fracturing treatment. The casing inner diameter is 4.5 inches (114.3 mm). The 726
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data. From Fig. 5, we can see that most of the deformed positions agree with fault positions very well. 3. Shape of casing deformation To identify the mechanism of casing deformation in this area, we need to know the shape of it. Caliper logs were used for the identification on some of the deformed wells. One of the logging results is shown in Fig. 6. The wellbore is measured by the use of a 24-arm caliper logging tool. The measured data were processed by logging specialized software. From the offset positions in the figure, we can see that the casing was probably undergone formation shear movement. Caliper logs of our other deformed wells exhibit the same shape. We also run coiled tubing with lead impression blocks into those deformed wells. During the trip into the well, this tool got obstructed at the deformed position and stopped. We then continue running the coiled tubing so that a weight can be applied to the tool. Typically, a 7000 lbs weight was applied to the lead impression blocks. The soft lead face is imprinted with the impact. The indentation can be interpreted to provide an indication as to the cause and type of obstruction within the well. One of the typical lead impressions is shown in Fig. 7. In this figure, the arc shape of the impression indicates that the casing deformed in the radial direction. The two sides of the deformed casing move to opposite directions, and the movement is around 21 mm. It indicates the same shape of the deformed casing as that of obtained from the caliper log. Both the caliper log measurements and the shape of the lead impression block suggest that the casing deformation is more likely due to formation shear. For the following analysis, we focus on the formation shear.
Fig. 3. (continued)
plug and perforation guns to the pre-designed position through wireline. However, because the casing diameter becomes smaller than the outer diameter of the bridge plug, the plug gets stuck at the deformed position. During field operations, we also notice that casing deformation can become severer as time goes by. During pumping a bridge plug, it got obstructed at position 1. After around 12 h, we pumped the same bridge plug, it happened 16 ft ahead of position 1, as noted by position 2. Then we changed a bridge plug with a smaller diameter. It passed the position 2 but got obstructed 7 ft ahead of the position 1. This is illustrated in Fig. 4. The casing deformation causes significant loss to the reservoir development. On one aspect, it brings downtime. Usually, when the bridge plug gets stuck, we pull it out and change another bridge plug with a smaller outer diameter. Sometimes, the wireline breaks when we pull it out. And we use coiled tubing to fish the guns and the plug. Significant non-productive time is caused. This is not the most important issue. If the casing deformation is severe enough, we cannot perforate the lateral between the deformed position and the last treated stage. This leaves an unstimulated lateral, which directly affects production. Currently, we have 72 hydraulic fractured horizontal wells that are in production. Among them, casing deformation happened to 38 wells. For the affected laterals, some of them were treated using diversion techniques, while some of them were simply abandoned. We projected the deformed positions in the ant-tracking plot, as shown by pink circles in Fig. 5. This plot is generated based on local seismic data, which were obtained by a 3D reflection seismic survey with a sampling interval of 2 ms and record length of 4s. The generation of ant-tracking plot is through the use of commercial software, which can incorporate seismic data and do further calculations. The algorithm inside first calculates the variance attribute of the seismic data to enhance the spatial discontinuities along the reflection layers. Then it improves the fault attributes by suppressing noise and remains of non-faulting events. These attributes map different seismic objects with high quality including fault surfaces (Randen et al., 2001). The advantage of this method is that the fault extraction can be automatically achieved from seismic
4. Model for fault slip One of the key features of unconventional reservoirs is the existence of natural fractures. These preexisting natural fractures and faults can serve as fluid conduits during hydraulic fracturing. Yang and Zoback (2014) studied microseismic events distributions for a well pad of Bakken formation. In their case, when fracturing Bakken formation, significant amounts of events were recorded in Mission Canyon formation, which is around 1000 ft above Bakken formation. Also, when fracturing one well for a stage close to the toe, microseismic events were recorded along the adjacent well close to the heel. Their further analysis confirmed that it is preexisting natural fractures and faults that serve as flow pathways during fracturing. In his work, he also set up a geomechanical model for the area of interest. Through his model, he analyzed the fault slip potential due to pore pressure elevation. Fisher et al. (2002) described a large hydraulic fracture diagnostic project in the Barnett Shale. This diagnostic project integrated tiltmeter and microseismic mapping. In this project, they observed a hydraulic fracturing job in one well killing other offset wells in Barnett Shale. It proves that a fracture network instead of only bi-wing fractures is
Fig. 4. Casing deformation becomes severer with time. The left figure shows the bridge plug got obstructed at an earlier time. The right figure shows it got obstructed at a later time, and the position is usually within 30 ft (a piece of casing length) ahead of the first position. 727
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Fig. 5. Ant-tracking plot with horizontal wells projected. The black color represents fault or pre-existing natural fractures. The pink circles along the laterals mark the casing deformation positions. The red hexagon shows the location of the pilot well with FMI log. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 6. Caliper log for a well with casing deformation. This measurement is from 24-arm caliper tool. There are 9 deformed locations along the 886-ft log interval. The maximum offset distance is 17 mm.
created during the hydraulic fracturing job. The development of the fracture network is highly variable. Unless we have a detailed fracture distribution for the formation, we cannot predict how fracturing fluids go and how the fracture network develops. This detailed fracture distribution for the whole formation is not quite possible with current technology. For the shale gas reservoir in the area of interest, tremendous amounts of preexisting natural fractures and faults also exist, which are identified from seismic data and formation micro-imager (FMI) log
data. The advantage of FMI log is that it can identify different types of fractures. The position of the pilot well in this study is shown in Fig. 5. The logged interval is 984 ft. From the FMI log, we can identify beddings, conductive fractures, and resistive fractures. Beddings are identified through their orientations, angles, and textures. Conductive and resistive fractures are identified through the resistivity. Fig. 8 shows the stereonet plot for these fractures. The dip angle of beddings is small, around 6°. The strike of beddings is around 135°. Since the beddings are almost horizontally 728
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Fig. 7. Lead impression block of a deformed position. The outer diameter of the lead block is 90 mm. The impression on the surface has a width of 11–12 mm. It is close to the wall thickness of the casing, which is 12.7 mm.
5. Stress state of the studied area A series of geophysical logs were also run for the pilot well, which are used to study the stress state of this area. The overburden stress for Longmaxi formation is calculated through the density log. To get the minimum horizontal stress, a diagnostic fracture test was conducted. From the pressure curve after shut-in, we can identify the formation closure pressure and pore pressure. Formation closure pressure is treated as minimum horizontal stress. From the FMI image log, we see clear drilling-induced tensile fractures (DITFs) for the depth of interest, which is used to constrain the range of the maximum horizontal stress. The friction coefficient is assumed as 0.67 (Zoback and Townend, 2001). The in-situ stress state for the depth of interest is presented by a stress diagram shown in Fig. 9. The parameters used to generate this diagram is shown in Table 2. In Fig. 9, the outer bound by the black line is from frictional strength equilibrium. The blue line represents the condition of DITFs. The spanned values by the green line are the ranges of Shmax given all the conditions above, which is 12,257.3–14225.6 psi. It is strike-slip faulting regime. The gradient for maximum horizontal stress is 1.31–1.52. Fig. 8. Stereonet plot illustrating the natural fractures measured through FMI log of the pilot well. The black, red and blue colors represent beddings, conductive fractures, and resistive fractures respectively. The algorithms for this plot are found in Allmendinger et al. (2012), Cardozo N. and Allmendinger R.W. (2013).(For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
6. Fault slip potential analysis Fault can slip when there is pore pressure perturbation. Healy et al. (1968) discussed the triggered earthquakes in Denver due to longtime wastewater injection. They believed that the mechanism by which fluid injection triggered the earthquakes is the reduction of frictional resistance to faulting, a reduction which occurs with an increase in pore pressure. Walsh and Zoback (2016) presented a framework for calculating the conditional probability of fault slip from pore pressure perturbation by modeling Mohr-Coulomb slip. The results can be used to assess the probability of induced slip on a known fault from a given injection-related pore pressure increase. Their approach provides a rigorous quantification of mapped fault slip potential, which incorporates uncertainties in relevant parameters. During a hydraulic fracturing treatment stage in the area of interest, normally around 12,000 barrels of slick water is pumped into formation within 2.5 h. Casing deformation usually happens after several stages of fracturing. That is around 60,000 barrels of fluid injection (if after 5 stages, which is common). If there are no natural fractures, the slick water just creates the main fracture and slowly leaks off into the formation. However, natural fractures are widespread in this shale formation, and we cannot predict where the fracturing fluids go. It may go into other layers, or flow along the wellbore through a preexisting conduit, as described by Yang and Zoback (2014). Nevertheless, there is
Table 1 FMI log measurements statistics. Pilot Well
Numbers detected
Dip angle, ˚
Strike, ˚
Beddings Conductive fractures Resistive fractures
449 17 20
6 6.1–88.4 15.6–76.2
Around 135 Majority around 132 Majority around 170
parallel, they are unlikely to slip when there are pore pressure perturbations. The further analysis below shows our speculation. The dip angles for conductive fractures vary from 6.1˚–88.4°. We may speculate that higher dip angles result in easy fault slips. The dip angles for resistive fractures vary from 15.6˚-76.2°. The statistics of the FMI log measurements for the pilot well is summarized in Table 1. 729
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Fig. 9. In-situ stress state at 9260 ft constrained by the frictional strength equilibrium and observed drilling induced tensile fractures through the FMI log. The green line represents the range of Shmax, and it lies in the strike-slip faulting regime. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 10. 2D stress state. σ1 is equivalent to the maximum horizontal stress and σ3 is equivalent to the minimum horizontal stress. β is the dip angle. σn is normal stress that is applied to the fault and τ is shear stress along the fault.
Table 2 Geomechanical parameters for the stress diagram. Parameters
Values
Depth Pore Pressure Pp Shmin Sv ΔP between mud pressure and pore pressure Thermal Expansion Tensile strength, T0 UCS, C0 Young's modulus, E Poisson's ratio
9350 ft 5668 psi 8105.5 psi 10,541.5 psi 607.3 psi 2.4 × 10−6 ˚C−1 negligible 17,400 psi 4.26 × 106 psi 0.11
which are 9248.4 psi, 6633.6 psi and 4708.3 psi respectively. σ1 and σ3 are calculated by subtracting pore pressure from Shmax and Shmin. Substituting these values into Eq. (2) and Eq. (3), we can get 868-psi shear stress, and 2255-psi effective normal stress. If we do the calculation for all fractures and show them in a scatter plot, as shown by Fig. 11, we can see the stress data of these fractures form a circle. The red, blue and black dots are for conductive fractures, resistive fractures and beddings respectively. The pink line is the fault slip criteria. We can see that all the black dots are grouped together, while the red and blue dots are distributed as a semicircle. This is because all beddings have similar dip angles and the dip angles for other fractures are varied. At the original state, all fractures are at their equilibrium state, as shown by Fig. 11a. When the pore pressure increases 500 psi across this logged interval, three fractures are likely to slip with one conductive fracture and two resistive fractures, as shown by Fig. 11b. There is a likelihood that casing deformation can happen. The conductive fracture is identified as 8796.6 ft depth with 110.8° strike and 53.2° dip angle. The two resistive fractures are identified as 9332.6 ft depth with 4.6° strike and 68.2° dip angle, 9333.4 ft with 358.2° strike and 68.8° dip angle. If somehow, there are no flow conduits to that fracture, and the hydraulic fracturing jobs cannot increase the pore pressure around that fracture, it will not slip. When the hydraulic fracturing jobs increase the pore pressure around some fractures by 2000 psi (Fig. 11c), these fractures slip and the likelihood for casing deformation is larger. It is very difficult for beddings to slip because the pore pressure around the beddings must increase by 3200 psi (Fig. 11d). This is unlikely to happen because fracturing fluids leak off to a natural fracture network. Therefore, we think previously published studies attributed casing deformation to movements of lithological layers are not correct. If we do the same calculation for an area of interest, we can identify how much pore pressure elevations are needed to induce fault slips areally. Fig. 12 shows the calculation results for some of our producing area (upper right part of Fig. 5). The left figure is the ant-tracking plot with horizontal wells and deformed locations projected. In the right figure, the faults are extracted from the original data. Each fault has its own depth, azimuth, and dip angle. The color on each fault represents how much pore pressure elevation is needed to induce its slip. Around 1,000 psi of pore pressure elevation is needed for some faults, and most of the deformed positions are close to those faults.
Sources Mini-frac Mini-frac Density log Mud density Lab experiments Lab experiments Lab experiments
a possibility that the slick water elevates the pore pressure near a fault. When the pore pressure increases, the effective overburden stress decreases, and the fault may slip. Below we provide a detailed analysis. The commonly used slip criteria for a fault is the Mohr-Coulomb (MC) criteria. It describes a relationship between effective shear stress and effective normal stress. The effective stress is defined by Terzaghi's law, as shown by Eq. (1).
=
pp
(1)
where σ′ is effective stress, σ is stress and pp is pore pressure. In this study, we consider the fault slip in a 2-dimensional domain. The problem is simplified as the radial extension stress state, as shown by Fig. 10. Considering the state equilibrium under the two stresses, we can derive the shear stress and normal stress applied to the fault, as shown by Eq. (2) and Eq. (3).
= 0.5( n
= 0.5(
3)sin
1 1
+
3)
(2)
2
+ 0.5(
1
3)cos
2
(3)
For every fracture that is detected by an FMI log, it has a dip angle, depth, and a fracture azimuth. We can calculate the effective normal stress and shear stress which are applied on it. For example, one of the fractures in Pilot Well-A is at the depth of 8407.6 ft and has a dip angle of 69.2°. The maximum horizontal stress, minimum horizontal stress, and pore pressure are calculated by their gradients time the depth, 730
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Fig. 11. Stability analysis of the fault planes in the Longmaxi formation. The red, blue and black dots are for conductive fractures, resistive fractures and beddings respectively. Four case scenarios are analyzed, (a) original state with no pore pressure perturbation; (b) a post-stimulation scenario from original state with 500 psi pore pressure increase; (c) a post-stimulation scenario from original state with 2000 psi pore pressure increase; (d) a post-stimulation scenario from original state with 3200 psi pore pressure increase. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
Fig. 12. a. Ant-Tracking plot with horizontal wells projected. The deformed positions are marked in the horizontal wells. b. Faults are extracted and faults slip potential is analyzed. The unit of color bar is psi. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.)
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plug and perforate. It does not affect the operation. This is the bestcase scenario. 2. If the smaller bridge plug cannot pass through the deformed position either, we pump down a dissolvable dummy plug with perforation guns to the predesigned position and perforate through a wireline unit. Before hydraulic fracturing, diverters are needed to plug the previous stage of fractures. The diameter of the dummy plug is slightly larger than the perforation guns and has a ring outside for pumping. If the dummy plug gets stuck during the pumping, we pump some salt water into the well to dissolve this plug. 3. If the dummy plug cannot get through the deformed position either, we run coiled tubing with perforation guns of smaller diameter to the designed position and perforate. 4. If smaller perforation guns cannot pass through the deformed position, we have to abandon the lateral between deformed position and last stage of fracturing. This is the worst-case scenario.
Table 3 Casing comparison in the area of interest.
Grade Outer diameter Inner diameter Wall thickness Internal yield pressure Collapse strength
Commonly used casing
Higher grade casing
Q125 5 1/2 inches 4 1/2 inches 12.7 mm 19,880 psi 20,663 psi
Q125 5.7 inches 4 1/2 inches 15.2 mm 19,880 psi 24,679 psi
7. Discussions Although casing deformation happens frequently for Longmaxi shale formation in Sichuan basin, rare cases were reported for shale formations across North America. One of the possible reasons is that the difference between maximum horizontal stress and minimum horizontal stress is large (approximate 1800–2000 psi, internal data). This can cause the Mohr circle to be larger and intersect with the fault slip criteria. At the current stage, we do not have comparisons with data of North America, but it deserves further research. The pre-existing fractures and faults can act flow conduits for fracturing fluids, as we reviewed earlier. Micro annulus in the cement sheath can also be a flow conduit if the cementing job is poor. Especially, during multi-stage hydraulic fracturing treatments, the casing undergoes repeat loading and unloading processes, which can cause the micro-annulus increase remarkably (Chen et al., 2017). Another important aspect is the scale of the slipping natural fractures. In this research, we assume each slipped natural fracture can cause casing deformation, but we believe its scale plays a role. Further research is needed on this perspective. Previous research also suggested utilizing high-grade casing or compliant cement (Dusseault et al., 2001). We had field trial for both two methods. We had 7 wells completed with high-grade casing. The wall thickness is 15.2 mm, which is 2.5 mm larger than the previouslyused casing. Among those 7 wells, 5 wells encountered casing deformation. A comparison between commonly used casing and the highgrade casing is shown in Table 3 below. From the table, we can see that the collapse strength is 20% larger than the previously used casing. However, the casing still deformed. The compliant cement we used is a type of foam cement. Compared with conventional cement, nitrogen is mixed in it so that gas voids can increase its final strength. It is widely used to cement wells in highstress environments (Crandall et al., 2014). We had two wells cemented with compliant cement. The casing of both the two wells deformed during multi-stage hydraulic fracturing. Due to limited amounts of tests, further field evaluation for this type of cement is needed.
The successful application of this operation mode in field proves that it is an effective method to handle casing deformation during hydraulic fracturing treatments. 9. Suggestions for preventing casing deformation Based on the analysis in this study, the only method to prevent casing deformation is to control the pore pressure elevation. This requires a controlled hydraulic fracturing scale. By doing this, future hydrocarbon production can be affected. If there are flow pathways to a critically stressed fault during fracturing, even small volume of fracturing fluids can cause critically-stressed faults to slip. In the meanwhile, as we can identify open fractures from FMI logs, we can have the portion of the laterals that penetrate the faults logged. Then we can identify the open fractures crossing the wellbore. By doing this, we can take preventive engineering actions in advance. 10. Conclusions In this study, we studied the casing deformation based on field measurements and a geomechanical analysis. The positions of casing deformation for 72 horizontal wells in Longmaxi shale gas formation are summarized and projected into the Ant-Tracking plot. The fault slip potential is analyzed for fractures from FMI log observations. Based on the observations and analysis, we can conclude this research as follows. 1. The caliper log measurements and lead print impression indicate that casing deformation is likely due to faults slip. 2. Pore pressure elevation due to hydraulic fracturing can cause fault slip. The deformed locations from our wells are close to the faults which are easier to slip. 3. Currently, there is no effective method for casing deformation prevention. However, a new approach for overcoming the operational difficulty is presented in this paper, which has been applied with success in field.
8. Innovative methods for stimulating deformed laterals The casing deformation brings great difficulty for pumping the bridge plug to the designated position. To stimulate the lateral between deformed position and last stage of fractures, we need to run the perforation gun through the deformed position. Previous operation method utilizes coiled tubing for the perforation operation. This takes much more time compared with wireline pumping. Our recent experience features a dissolvable dummy bridge plug for wireline pumping, which can save a coiled tubing run. Generally, there are four scenarios when casing deformation happens.
Acknowledgment The authors thank Great Wall Drilling Company (a subsidiary of China National Petroleum Corporation), for providing financial support, the datasets, and core samples for this study. Appendix A. Supplementary data
1. If the casing deformation is not severe and a bridge plug of smaller diameter can get through, we pump this bridge plug with perforation guns to the designed position through a wireline unit, set the
Supplementary data to this article can be found online at https:// doi.org/10.1016/j.petrol.2019.02.068. 732
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Nomenclature σ σ′ τ pp β Sv Shmin Shmax
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normal stress effective normal stress shear stress pore pressure dip angle overburden stress minimum horizontal stress maximum horizontal stress
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