Zeng, Yijin (SINOPEC Research Institute of Petroleum Engineering) | Gao, Yuan (SINOPEC Research Institute of Petroleum Engineering) | Zhou, Shiming (SINOPEC Research Institute of Petroleum Engineering) | Tao, Qian (INOPEC Research Institute of Petroleum Engineering) | Sang, Laiyu (SINOPEC Research Institute of Petroleum Engineering) | Yang, Guangguo (SINOPEC Research Institute of Petroleum Engineering) | Lu, Peiqing (SINOPEC Research Institute of Petroleum Engineering)
Many challenges exist in ultra-deep high-temperature and high-pressure gas well cementing, such as, high-temperature, active gas layer, narrow density window, and seal integrity failure of cement sheath, which brings huge difficulties in anti-gas channeling cementing. By selecting the nano-liquid silicon and latex anti-gas channeling agents, and synergistically enhancing the anti-gas channeling performance of cement slurry, the mechanical properties of cement set is improved; by optimizing the compounding and dosage of silicon powder with different particle sizes, the high-temperature stability of cement set is enhanced. Via the selection of inorganic fiber cracking-prevention and plugging system, the crack propagation is inhibited, and the leakage resistance of cement slurry and the impact resistance of cement set are improved. Hence, a high-temperature resistant latex anti-gas channeling cement slurry system was developed. The cement slurry system has the following properties: API water loss of <50 mL at 180 °C, SPN value of <1, cement set compressive strength of 39.3 MPa under 200 °C×21 MPa×60 d, Young's modulus of 6.9 GPa, gas layer permeability of 0.004×10-3 μm2, and its comprehensive mechanical properties are better than that on the 30th day. The cement sheath seal integrity evaluation shows that the 26.7 mm sheath can achieve an effective seal effect under the cyclic loading process (peak pressure is 90 MPa). Combined with the staged gas layer stability prediction, the pressure management cementing technology under unsteady conditions was proposed, which solves the problems of gas channeling and leakage prevention in ultra-deep high-temperature and high-pressure reservoirs with enriched fracture-cavity. The anti-gas channeling cementing technology has been used in the Shunnan and Shunbei plays of Sinopec Northwest Oilfield Company, and it can provide references for the cementing of similar gas wells.
Wang, Hao (China University of Petroleum) | Zhang, Hui (China University of Petroleum) | Li, Jun (China University of Petroleum) | Zeng, Yijin (Sinopec Research Institute of Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute of Petroleum Engineering) | Tao, Qian (Sinopec Research Institute of Petroleum Engineering)
Shale has significant bedding structure and different mechanical properties in various directions. The formation temperature increases with well depth. The principle of shale drillability changing with drilling direction and formation temperature affects the safety and efficiency of shale gas drilling.
This paper conducted shale drillability testing experiment in different directions and at different temperatures with shale samples from Longmaxi formation, Sichuan Basin, China. Firstly, the differences of shale drillability at different formation temperature with different drilling directions are analyzed. The shale drillability anisotropy index and the change rule of drillability are evaluated. Then, a shale drillability prediction model considering well trajectory and the formation temperature is built up based on geometry and regression. Finally, the principle of shale drillability changing with the drilling direction and the temperature is analyzed with rock mechanics theory.
The results show that the drillability of the shale in Longmaxi formation has obvious anisotropy, and the drillability grade in vertical direction is about 24.6% higher than that in parallel direction. Under the same drilling direction, the shale drillability increases with the rising temperature. The anisotropy of shale drillability decreases gradually with the increase of temperature and it follows approximatively power law in the experimental range. Optimizing drilling trajectory to adjust the drilling direction and controlling suitable bottom hole temperature are the guarantee of the optimal and fast drilling.
This study proposed a novel prediction method for the drillability of the shale at different formation temperature, which has important significance for providing guidance for the design of well trajectory and temperature control.
Shale gas is an important unconventional oil and gas resource, which has great mining and economic value. As the reservoir of shale gas, shale has a significant bedding and anisotropy characteristics. At present, many international scholars have studied the anisotropy of shale (Mokhtari, M. et al., 2013; Heng Shuai et al., 2014). The failure criterion of the isotropic rock is established by Jaeger, J. C. et al based on the experimental and theoretical analysis (Jaeger, J. C., 1960; Yong, M. T. et al., 2001; Nasseri, M. H. B. et al., 2003). Simpson, N. D. J. et al studied the effect of the anisotropic shale on the Brazilian tensile test (Simpson, N. D. J. et al., 2014). Wang Hu et al analyzed the anisotropy of the elasticity modulus, Poisson’s ratio and compressive strength of the shale (Wang Hu et al., 2017). Ai Chi analyzed the brittleness anisotropy of the shale and calculated the shale brittleness index of the different direction with a new method (Ai Chi et al., 2017).
Zhang, Ruxin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum) | Hou, Bing (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, and State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum) | Zeng, Yijin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zhou, Jian (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Li, Qingyang (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Traditional hydraulic fracturing requires lots of water and sand resulting in short fracture length and small SRV with a low production. However, a new waterless fracturing, called Liquefied Petroleum Gas (LPG) fracturing, is applied to stimulate shale formation effectively.
In order to figure out the mechanism of fracture initiation and propagation in LPG fracturing, four large-scale true tri-axial fracturing simulation experiments have been conducted on shale outcrops. Meanwhile, the effects of engineering factors, pump rate and fluid viscosity, on fracture propagation behavior in the shale formation are discussed.
The experimental results indicate that LPG fracturing not only activates discontinuities to form a complex fracture network, but also enhances induced fracture length to form a large SRV. Induced fractures have two initiation points, open-hole section and stress concentration point of wellbore wall, and have three main propagation behaviors, crossing, shear and arrest, dilation and crossing in shale formation. A low viscosity fracturing fluid activates discontinuities resulting in complex fractures, whereas, a high viscosity fluid would like to create some main fractures without opening discontinuities. Moreover, a high pump rate offers more energy for induced fractures to cross the discontinuities resulting in a long fracture length and large SRV. In addition, the anisotropic of shale formation and the existence of discontinuities cause signals attenuation, which increases the arrival time, resulting in location deviation of acoustic emission (AE) events in the AE monitoring. The pressure-time-energy curve, however, shows that the fracture initiation is earlier than the sample ruptured. That is, the initiation pressure is smaller than the ruptured pressure.
The experiments conducted in this paper prove that the LPG fracturing indeed has some advantages than traditional hydraulic fracturing, such as long fracture length and large SRV. And then, the research results provide the theoretical basis for the LPG fracturing operation in shale formation.
Zeng, Yijin (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Xia, Yang (China University of Petroleum) | Ding, Shidong (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Jin, Yan (China University of Petroleum) | Yang, Zhi (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Lu, Yunhu (China University of Petroleum)
ABSTRACT: Advances in multistage fracturing combined with horizontal drilling have made this technique the driving force for the recent spectacular success in shale gas development and production. In this paper, a hierarchical approach integrating discrete fracture networks with multi-continuum concept is proposed to model various coupling mechanisms of gas nonlinear transport in shale. The hybrid model is composed of three continuum layers: organic matter, inorganic matter and micro-fractures in matrix which are treated as a continuum medium, and the discrete fractures are embedded into the micro-fracture-continuum. The extended finite element method is employed to decouple the mesh conformity between the mesh of media and the discrete fractures. The results of long-term well-performance dynamics are used to show the power and flexibility for simulating the multi-continuum/discrete-fracture interactions during gas transport in shale. The effects of fracture geometry and coupling flow mechanisms on gas production are also analyzed in this paper.
Zhou, Jian (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zeng, Yijin (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Jiang, Tingxue (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zhang, Baoping (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Shen, Boheng (Missouri University of Science and Technology) | Zhou, Jun (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering)
ABSTRACT: The multi-staged fracturing is becoming one of the key strategies for the shale gas development worldwide. The impact of stress shadow and natural fractures on fracture could cause unexpected fracture geometry in this case. The staged fracture initiation and fracture geometry during fracturing in shale are investigated through a series of tri-axial fracturing experiments. The shale blocks made by fresh shale outcrop were tested with a varied of perforation intervals as 80mm, 120mm, 160mm, 200mm, respectively. The testing results demonstrated that the multi-fracture interference occurred and it caused complex unbalanced facture geometry when the notch interval was 80mm and 120mm. By real-time diagnosis with microseismic(MS) data, we found that due to the double effect of stress shadow and natural fracture, the second fracture tends to be much shorter compared with the first fully developed fracture. Meanwhile, the direction of the second fracture tends to be a diverging fracture. However, the obvious effect of stress shadow was not found in our tests when the notch interval was 160mm and 200mm. At last, a simple mode for effective stimulation of reservoir volume (ESRV) calculation based on MS data was introduced to compare individual ESRV for different fracture geometries.
With the development of shale gas in the last decades, horizontal multi-stages hydraulic fracturing have more and more become valuable technique for stimulation of shale reservoirs. In naturally fractured shale reservoirs, the widely held assumption that the hydraulic fracture is an ideal, simple, straight, bi-wing, but planar feature is untenable because of natural fractures, faults, bedding planes and stress contrasts. In this kind of shale reservoirs due to interaction with natural fractures or frictional interface, the fracture may propagate asymmetrically or in multiple strands or segments.
The presence of natural fractures alters the way the induced fracture propagates through the rock. The early studies (Zoback, 1977; Daneshy, 1974; Lamont and Jessen, 1963; Blanton, 1982) have shown that the propagating fracture crosses the natural fracture, turns into the natural fracture, or in some cases, turns into the natural fracture for a short distance, then breaks out again to propagate in a mechanically more favorable direction, depending primarily on the orientation of the natural fracture relative to stress field. A fracture interaction criterion to predict whether the induced fracture causes a shear slippage on the natural fracture plane leading to arrest of the propagating fracture or dilates the natural fracture causing excessive leak-off was proposed based on mineback experiments (Warpinski and Teufel, 1987). A simple criterion for crossing was proposed by applying a first order analysis of the stresses near a mode I fracture impinging on a frictional interface oriented normal to the growing fracture (Renshaw and Pollard, 1995). According to their work, crossing will occur if the magnitude of the compression acting perpendicular to the frictional interface is sufficient to prevent slip along the interface at the moment when the stress ahead of the fracture tip is sufficient to initiate a fracture on the opposite side of the interface. Scaled laboratory experiments and numerical tests proved that high flow rate or viscosity yields fluid- driven fractures, while low flow rate just opens an existing fracture network (Beugelsdijk and de Pater, 2000, 2005). Laboratory scale tests also found that interaction of a hydraulic fracture with a natural fracture depended heavily on the stress state, inclination of the natural fracture with respect to the hydraulic fracture, and the strength of the natural fracture (Zhou et al., 2010 and Ingraham et al., 2016). For the case of natural fractures in shale are mineralized, researchers embedded planar glass discontinuities into a cast hydrostone block as proxies for cemented natural fractures and used these blocks to perform tests to examine the effects of cemented natural fractures on hydraulic fracture propagation. Their results show that obliquely embedded fractures are more likely to divert a fluid-driven hydraulic fracture than those occurring orthogonally to the induced fracture path (Olson et al., 2012).
Wang, Hao (China University of Petroleum-Beijing) | Zhang, Hui (China University of Petroleum-Beijing) | Li, Jun (China University of Petroleum-Beijing) | Zeng, Yijin (Sinopec Research Institute of Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute of Petroleum Engineering) | Tao, Qian (Sinopec Research Institute of Petroleum Engineering)
In the development and production process of offshore heavy oil thermal recovery wells, the rise of annulus fluid temperature will lead to extremely high annular pressure, which will threaten the casing safety and wellbore integrity. Nitrogen injection is often applied to release the annular pressure. However, insufficient injection can't solve the problem and too much nitrogen will lead to economic loss and poor effect. Therefore, there exists an optimal injection volume in nitrogen injection operation.
In this study, based on the thermodynamic principle and the PVT equation, the reducing mechanism of the nitrogen physical properties and injection volume for annular pressure was analyzed and a calculation method is presented. Then a well in Bohai sea of China is taken as an example to calculate the optimal injection volume and analyze the influence of nitrogen physical properties, annulus temperature and casing strength parameters on the optimal injection volume. At last, the prediction model of the optimal injection volume of annulus nitrogen and a safety evaluation method for production string under nitrogen injection are proposed and some optimization methods are given for nitrogen injection.
The results show that nitrogen injection can effectively reduce annular pressure over 40%. With the increase of nitrogen injection volume, the reduction rate of annular pressure and the injection efficiency decreases gradually. The optimal injection volume of annulus nitrogen is mainly determined by annulus temperature, intial temperature and pressure of nitrogen. Injecting nitrogen at the optimal volume can maximize the economic and safety benefit. It is necessary to control injection volume when taking nitrogen injection operation.
This work provides a prediction model for determining the optimal nitrogen injection volume to reduce annular pressure buildup, and a production string safety evaluation method was also proposed. These can provide guidance for field nitrogen injection operation.
The annular pressure buildup is a widespread issue in the offshore thermal recovery wells and HTHP wells. The annular pressure buildup is the abnormal high pressure in the wellhead annulus fluid between casings or the tubing and the casing. In the process of steam injection or early stage of production of offshore thermal production wells, there is great difference in temperature between injected hot steam and the enviroment of the casing pipe and the liquid in annulus (Toni Loder et al. 2003). Moreover, the temperature field changes sharply and the liquid trapped in the annulus will expand, leading to high annular pressure. Consequently, it might damage the wellhead equipments and cause great economic loss, even leads to serious safety accidents. Several approaches are adopted in the field to prevent the increase of the annular pressure, including installing mechanical devices on wellhead (Richard F. Vargo et al. 2002), injecting gas like nitrogen into the annulus (Toni Loder et al. 2003; Bo Zhang et al. 2016) and wrapping compressible materials around the casing and tubing (U. B. Sathuvalli et al. 2016), etc. Previous researches of sealed annular pressure mainly focus on the model building of sealed annular pressure and the management of the casing annular pressure. In this paper, the approach to release the annular pressure by injecting nitrogen is studied. The analysis of reducing mechanism of the gas physical characteristics and injection volume for annular pressure was performed. Then the influence of gas physical characteristics, annulus temperature increment and casing physical parameters on optimal injection volume is analysed based on a well in Bohai sea in China. Finally, a prediction equation of annulus nitrogen optimal injection volume is proposed and a string safety evaluation method is given.
Many researchers have conducted study on mechanism of single phase of CO2 or H2S corrosion to cement stone, but the corrosion mechanism of CO2/H2S mixture to cement is seldom involved. The fact is that most of sour gas fields contain CO2/H2S mixture, for example, Puguang gas reservoir in China contains H2S and CO2 as high as 15% and 8% by volume. In this paper, test methods are established under bottomhole condition of Puguang gas reservoir, changes of compressive strength and permeability of corroded cement stone samples by H2S/CO2 mixture are evaluated to study corrosion mechanism of CO2/H2S mixture to cement stone.
Slurry is prepared according to API Spec10B and poured into test mold and cured in HTHP cell for 24 hours. The half of set samples are removed from molds and numbered and putted into the corroding chamber and cured for 21 days, then seal the chamber and inject CO2/H2S mixture and apply heat and pressure according to required temperature and CO2/H2S partial pressure. The rest are cured in HTHP cell as comparative samples. The temperature and pressure in the chamber keep constant during the test.
Compressive strength and permeability cement stone samples were tested to probe the changes before and after corrosion. Microstructure and corroded products of samples were observed by SEM and XRD to investigate changes before and after corrosion.
Result shows the corroded products of CO2/H2S mixture to cement are similar to those by single-component H2S or CO2 gas, except that the amount of expansive crystal produced by H2S is reduced. Combination of H2S and CO2 accelerates the corrosion progress, the recession of strengthen and permeability is more serious than that of single H2S or CO2, but CO2 dominates the whole corrosion process after the long duration. Fly ash and Clay have benefits to resist corrosion of combination of H2S and CO2.
The CO2/H2S mixture will bring serious corrosion on cement ring in wet environments, and damage its' seal ability. The higher the temperature, the more severe of the recession of strengthen and permeability, which presents a complete opposite rule with corrosion by H2S or CO2. The composition of cement slurry is the predominant factor affecting cement corrosion resistance. The introduction of Latex and Fly ash and clay into system will reduce the alkalinity in the cement slurry system and improves the corrosion resistance. The hydration products are crystallized after corrosion under combination of H2S and CO2, and loose arrangement of those crystals is the reason of strength decline and permeability rise.
Zhou, Jian (Sinopec Research Institute of Petroleum Engineering) | Zeng, Yijin (Sinopec Research Institute of Petroleum Engineering) | Jiang, Tingxue (Sinopec Research Institute of Petroleum Engineering) | Zhang, Baoping (Sinopec Research Institute of Petroleum Engineering) | Zhang, Xudong (Sinopec Research Institute of Petroleum Engineering)
This reservoir is a tight gas field and the target sand stone zones are generally staged fracturing treated at depths of roughly 1500 to 2800 meter. Knowing the direction or azimuth of the fracture orientation is important in development of this low permeability reservoir with horizontal wells. The paper presents surface tiltmeter hydraulic fracturing mapping results of 15 stages treatment in two horizontal wells at the same operational period. The two wells are part of a cluster of six horizontal wells located in North of Yulin, Shanxi province. Application of this technology is important in this tight gas field where fracture stimulation is a key method for production enhancement and reservoir development. This was the first deployment of tiltmeter mapping on a cluster of horizontal wells, and several modifications were made for the standard procedures. Using an array of 54 Surface Tiltmeters, the mapping was performed on all 15 treatments with the average perforation depths of TVD 2540 to 2545m at each horizontal section to determine hydraulic fracture azimuth and fracture length, respectively. For the first horizontal well R-3H, the tiltmeter mapping results show that, the azimuth of fractures is between N53 °E and N71 °E, and the fracture half length for stages fractures is between 112m and 149m. For the second horizontal well R-5H the tiltmeter mapping results show that, the azimuth of fractures is between N67 °E and N76 °E, and the fracture half length for stages fractures is between 107m and 142m. Besides, in the well R-3H from stage 7 to stage 9, the horizontal volume component of fractures, increased from 17% to 34%, as well as in the well R-5H from stage 5 to stage 9, the horizontal volume component of fractures significantly increased to 69% from 20%. Meanwhile, the production of the two wells after the fracturing was the first and second among the cluster of the six horizontal wells, respectively. Thus, by using the synchronous fracturing technology, we believe that it not only improved the complexity of the staged fractures between the two wells but also led to a better production enhancement.