Mou, Jianye (China University of Petroleum Beijing, State Key Laboratory of Petroleum Resources and Prospecting) | Yu, Xiaoshan (Sichuan-to-East Natural Gas Transmission Pipeline Branch Company of SINOPEC) | Wang, Lei (China University of Petroleum, Beijing) | Zhang, Shicheng (China University of Petroleum, Beijing) | Ma, Xinfang (China University of Petroleum, Beijing) | Lyu, Xinrun (China University of Petroleum, Beijing)
Jianye Mou, China University of Petroleum, Beijing, State Key Laboratory of Petroleum Resources and Prospecting; Xiaoshan Yu, Sichuan-to-East Natural Gas Transmission Pipeline Branch Company of SINOPEC; and Lei Wang, Shicheng Zhang, Xinfang Ma, and Xinrun Lyu, China University of Petroleum, Beijing Summary Natural fractures have significant influence on flow fields, thus affecting wormhole pattern in acidizing. First, statistical natural-fracture models are established using the Monte Carlo method. Second, a two-scale continuum wormhole model is established to simulate wormhole propagation with natural fractures. Finally, extensive numerical simulation is conducted to investigate wormhole behavior and the effect of the natural-fracture parameters on wormhole pattern. In addition, possible wormhole-penetration distance is discussed. Introduction Matrix acidizing in carbonates is a typical measure to remove formation damage caused by drilling, completion, and other operations. The wormholes created in acidizing penetrate the damaged zone, thereby removing the damage and stimulating the reservoir. Stimulation performance depends on wormhole pattern, which in turn is influenced by many factors such as acid properties, injection rate, formation properties, and natural fractures.
Mou, Jianye (Shaodan Tao China University of Petroleum-Beijing) | Hui, Xuezhi (Seventh Oil Production Plant of Changqing Oilfield of CNPC) | Wang, Lei (China University of Petroleum-Beijing, State Key Laboratory of Petroleum Resources and Prospecting) | Zhang, Shicheng (China University of Petroleum-Beijing, State Key Laboratory of Petroleum Resources and Prospecting) | Ma, Xinfang (China University of Petroleum-Beijing, State Key Laboratory of Petroleum Resources and Prospecting)
Multi-stage acid fracturing of horizontal wells is a necessary and effective technology in developing tight carbonates. In open-hole horizontal wells in high-temperature, naturally fractured deep formations, segmentation with tools is of high risk and costly, even ineffective sometimes, so segmentation with diversion agents is alternative to tools and was pilot tested in some fields. The stimulation results were satisfactory, and pressure response feature was in accord with expectation. However, this technique has not been studied experimentally or numerically extensively yet.
In this study, we investigated tool-free multi-stage fracturing experimentally in open-hole horizontal wells with diversion agents. Firstly, we designed a multi-stage tri-axial fracturing system and experimental procedures to satisfy the requirements of diverted fracturing in horizontal wells. Next we conducted a series of experiments to investigate feasibility of multi-stage fracturing with diversion agents using natural carbonate outcrop cubic blocks with the size of 300*300*300mm. CT scanning was used to obtained detailed fracture geometry after experiment. Finally we analyzed the effect of diversion agent type, concentration, and injection procedure on diversion.
The experimental results show that multi-stage fractures perpendicular to the open-hole horizontal wells was created, which verifies the validity of the tool-free multi-stage fracturing of open-hole horizontal wells with diversion agents. Proper agents or combinations can effectively plug the fracture generated previously and generate pressure high enough to initiate another fracture. The breaking pressure or propagation pressure of second fracture was monitored higher than the one of the first fracture. Under experiment conditions, 1-3mm fiber or combination of fiber and particle (0.8-1.2mm) can effectively plug fractures and realize segmentation. Concentration of diversion agents tested ranges 0.4-1.6wt%. Injection procedure for two-stage fracturing was fracturing fluid + diversion fluid + fracturing fluid. The amount of diverter and open-hole length are the vital factor for the success of experiments.
This study newly designed a multi-stage tri-axial fracturing system and experimental procedures for the diverted fracturing. The finding verified the validity of the tool-free multi-stage fracturing of open-hole horizontal wells with diversion agents and provides fundamental for field treatment design.
Mou, Jianye (China University of Petroleum Beijing, State Key Laboratory of Petroleum Resources and Prospecting) | Yu, Xiaoshan (Sichuan-to-East Natural Gas Transmission Pipeline Branch Company of SINOPEC) | Wang, Lei (China University of Petroleum Beijing) | Zhang, Shicheng (China University of Petroleum) | Ma, Xinfang (China University of Petroleum Beijing) | Lyu, Xinrun (China University of Petroleum Beijing)
Jianye Mou, China University of Petroleum, Beijing, State Key Laboratory of Petroleum Resources and Prospecting; Xiaoshan Yu, Sichuan-to-East Natural Gas Transmission Pipeline Branch Company of SINOPEC; and Lei Wang, Shicheng Zhang, Xinfang Ma, and Xinrun Lyu, China University of Petroleum, Beijing Summary Natural fractures have significant influence on flow fields, thus affecting wormhole pattern in acidizing. First, statistical natural-fracture models are established using the Monte Carlo method. Second, a two-scale continuum wormhole model is established to simulate wormhole propagation with natural fractures. Finally, extensive numerical simulation is conducted to investigate wormhole behavior and the effect of the natural-fracture parameters on wormhole pattern. In addition, possible wormhole-penetration distance is discussed. This study provides a theoretical basis for matrix-acidizing designs in naturally fractured carbonates. Introduction Matrix acidizing in carbonates is a typical measure to remove formation damage caused by drilling, completion, and other operations. The wormholes created in acidizing penetrate the damaged zone, thereby removing the damage and stimulating the reservoir.
Sand-slug fracturing has been the main fracturing pumping mode due to the tightness of shale. This mode makes it easier to inject proppants. However, it may cause poor connectivity in the middle brittle formation due to the discontinuous propping. This paper describes an attempt to fracture the unconventional shales with conventional sand-ramp fracturing pumping mode. The results show that good effect is achieved compared with the sand-slug fracturing mode used in the adjacent wells.
Shale reservoir reconstruction has large construction displacement and high pressure, and it adopts fracturing technology of slickwater and linear glue
The Sand-ramp modes using less fluid and higher sand content
Based on the understandings on geological characteristics and formation property, the sand-ramp fracturing pumping mode was designed. Two of six wells in the pad were selected to apply this mode. To maximize the stimulated reservoir volume, slickwater accounted for 40% to 60% of the total injected fluids. 100-mesh quartz sands were pumped in priority to improve the complexity of fracture. Then, the 40-70 mesh ceramsites was pumped with crosslinked gel to support the primary, secondary and natural fractures. The pumping rate is 12-13 cubic meters per minute and no acid is used throughout the whole pumping process.
The maximum proppant concentration of sand-ramp reached to 480 kilogram per cubic meters, which was much higher than that of sand-slugs. As a result, good propped fractures were obtained. Since no fluid sweep was used after the sand-slug, the average fluid injection per stage is declined by 27%, but the average sand injection volume was increased by 17%, which significantly reduced the cost and the possible influence to environment. With the sand-ramp mode, the highest test production of the block was up to 278500 cubic meters per day. This well produced 35 million cubic meters of shale gas in 270 days.
The practicability of the sand-ramp pumping mode used in unconventional shales is proven to be positive, especially in the formation with high horizontal stress difference. However, the development result needs to be continuously studied.
Zhang, Lufeng (China University of Petroleum) | Zhou, Fujian (China University of Petroleum) | Wang, Jie (China University of Petroleum) | Wang, Jin (China University of Petroleum) | Mou, Jianye (China University of Petroleum) | Zhang, Shicheng (China University of Petroleum)
ABSTRACT: Acid propped fracturing is a valid stimulation technique applied in deep carbonate reservoirs and its effect mainly depends on the conductivity. However, short-term conductivity experimental data used in existing acid propped fracturing design may not be directly applicable to real case. Aiming at this problem, this paper investigates impacts of acid-rock contact time, acid etched fracture creep, proppant size and concentration on the long-term conductivity. The study shows that the acid propped fracture retained enough conductivity under high closure stress. Gelled acid fracture conductivity increases with the longer time until it reached the upper limit when the contact time is 60 minutes. The long-term conductivity experiments show that conductivity decreased sharply in the 48 hours and underwent a gradual decline from 48 hours to 96 hours followed by the steady state after 120 hours. The ideal combination of proppant size and concentration are optimized at different stress level. An acid propped fracture conductivity correlation was also developed for calculating the conductivity. This study provides an insight of optimizing acid propped fracturing design and predicting well performance.
As significant domains of oil and gas exploration and development, carbonate reservoirs constitute almost 60% of the world's remaining oil and gas. Acid fracturing, as a conventional and effective stimulation method, has been widely used in carbonate formation (Amirhossein and Maysam, 2016). However, due to serious acid leakage and rapid acid-rock reaction speed resulting from high temperature and closure stress in deep well, the length of effective acid etched fracture is limited and the effective duration of acid etched fracture is short (Li Y et al., 2009; Suleimenova A et al., 2016;). Consequently, uniting the deep penetration of acidizing with proppant fracturing is a natural progression toward great effective stimulation of deep carbonate reservoirs. Acid propped fracturing, combining the advantages of propped fracturing and acid fracturing, is the technology that can not only readily carry proppant but also react with the carbonate formation to eliminate the formation damage. It also can connect natural fracture, maximizing the drainage area and the stimulation reservoir volume (SRV).
Hou, Tengfei (China University of Petroleum, CUPB) | Zhang, Shicheng (China University of Petroleum, CUPB) | Li, Dong (China University of Petroleum, CUPB) | Ma, Xinfang (China University of Petroleum, CUPB)
Uniform proppant distribution in multiple perforation clusters plays a crucial role on sufficiently propping fractures conductivity in hydraulic fracturing. These propped fractures and their effectiveness is critically influenced by the in situ stress in the formation. As great uncertainty exists in uneven propped fracture, this paper examines the impact of proppant distribution and fracture conductivity variation on the gas productivity for shale gas reservoirs, by developing a reservoir simulation model.
In this paper, numerical reservoir simulation, which involves application of a constantly decreasing permeability to the propped fracture, are used to model the uneven proppant distribution and geomechanics effect. The decrease of permeability, along from the wellbore toward the tip, is simulated using an exponential approach, as well as a linear approach. Moreover, Effects of gas desorption and stress-dependent fracture conductivity are taken into account in this model. Sensitivity analysis is carried out on critical parameters to quantify the key parameters affecting gas productivity between uniform and nonuniform proppant distribution. The degree of non-uniform proppant distribution is also investigated and divided into four types of proppant distribution scenarios.
The following conclusions can be obtained based on the simulation results. A big difference on well performance between the case of linear and exponential permeability degradation is observed. The pressure distribution comparison shows higher pressure drops in the exponentially decreasing permeability case, which results in a lower gas production. Reservoir permeability plays a critical role in cumulative gas production, no matter in case of permeability exponentially degrading or linear degrading, followed by fracture half-length, primary fracture conductivity, Fracture complexity, permeability anisotropy. Furthermore, the effect of uneven proppant distribution between different clusters can significantly reduce the gas recovery, especially in low proppant concentration and small fracture conductivity.
The model presented in this paper takes the uneven proppant distribution and geomechanics effect into consideration and shows good agreement with real field production. This paper can demonstrate its own merits on the optimization of hydraulic fracturing treatments, and provide a better understanding of the effect of proppant distribution on well performance.
Zhou, Tong (China University of Petroleum in Beijing) | Zhang, Shicheng (China University of Petroleum in Beijing) | Zou, Yushi (China University of Petroleum in Beijing) | Ma, Xinfang (China University of Petroleum in Beijing) | Li, Ning (China University of Petroleum in Beijing) | Hao, Siying (China University of Petroleum in Beijing) | Zheng, Yonghua (Schlumberger Zhongyu Shale Gas Technical Services Chongqing)
The Lujiaping shale gas formation in Sichuan Basin, SW China, is 1400m deep and has high dip angles. Moreover, it is also subjected to the strike-slip fault geostress and contains highly developed bedding planes and natural fractures. The complex geologic condition makes the fracturing treatment effect hard to predict. This paper aims to establish a simulation model to predict the created hydraulic fracture geometry so as to provide appropriate stimulation strategy. Based on the discrete element method, a novel three-dimensional fracture propagation model is established. The transverse isotropy constitutive relations are primarily introduced to characterize the layered shale in the high dip angle formation. Then, the model is used to investigate how the hydraulic fracture geometry changes with different parameters, such as in-situ stress distribution, natural fracture density, fluid viscosity, and pump rate. The model is validated through experimental data, which shows the simulation result is in accordance with the experimental observation. Taking the complex geologic conditions as the initial condition and assuming the formation dip angle as 50°, the high differential stress which is the difference between overburden stress and minimum horizontal stress enhances the fracture propagation in the vertical direction. At 5 MPa of differential stress, the increase of fracturing fluid viscosity can reduce the influence of bedding plane on fracture geometry. The increase of pump rate is helpful to decrease the restriction of bedding plane on fracture propagation so as to improve the stimulation effect. In addition, the high density of natural fracture will further enlarge the impact on the fracture geometry. This work is a theoretical study of predicting the hydraulic fracture geometry under complex geologic conditions, which provides the technical guidance for the optimization of the fracturing treatment in Lujiaping shale gas formation.
Hou, Tengfei (China University of Petroleum, CUPB) | Zhang, Shicheng (China University of Petroleum, CUPB) | Yu, Baihui (China University of Petroleum, CUPB) | Lv, Xinrun (China University of Petroleum, CUPB) | Zhang, Jingchen (Heriot-Watt University) | Han, Jingyu (China University of Petroleum, CUPB) | Li, Dong (China University of Petroleum, CUPB)
Channel fracturing, which greatly increase fracture conductivity by the creation of open channels inside fracture, has proved to be a novel stimulation technology that widely used in unconventional reservoir. The objective of this paper is to study the stimulation mechanism of channel fracturing by the combination of theoretical analysis and experimental research. However, for channel fracturing scenario, the currently available models are not accurate and appropriate in terms of prediction of proppant embedment and fracture conductivity in channel fracturing.
In this paper, new analytical models are derived to compute the proppant embedment, proppant deformation and fracture conductivity in channel fracturing. The mass deformation model and creeping deformation model are adopted to predict the change of proppant embedment and fracture conductivity over time. Many factors affecting the results of proppant embedment and conductivity, including closure pressure, elastic-plastic properties, properties of viscoelastic proppant and rock are investigated. Experimental researches are also conducted to evaluate conductivity at different closure pressures for the fractures of steel plate, shale and sandstone. Besides, the proppant embedment and proppant deformation are measured through the proppant embedment testing instrument, and the proppant distribution before and after experiments are comparatively analyzed.
The results show that the new analytical model proposed fits well with the experimental data, which verifies the accuracy and the feasibility of this model, though the decline rate of experimental data is a little bit faster than that of the model. The fracture conductivity is directly proportional to proppant viscosity, elastic modulus of proppant and inversely proportional to closure pressure, while elastic modulus of rock and large value of formation rock viscosity have slight impact on fracture conductivity. Moreover, the steady state of conductivity has been studied, and Comparisons between channel fracturing and conventional fracturing are analyzed in several aspects. The experimental results also reveal that the overall dimensions of created open channel may decrease or disappear due to the forced of formation stress.
Technical innovations in this paper are (a) new analytical models, including the mass deformation model and creeping deformation model, are adopted to predict the change of proppant embedment and fracture conductivity (b) Experimental tests are also performed to measure conductivity and proppant embedment at different closure pressures. This paper can demonstrate its own merits to show the advantage of channel fracturing technology.
khair, Elham Mohammed M. (Sudan University of Science & Technology) | Zhang, Shicheng (China University of Petroleum, Beijing) | Abdelrahman, Ibrahim Mustafa (Sudan University of Science & Technology)
The current study presents elastic properties model for Fulla Oilfield in northeast of Block 6 in south of Sudan. Due to the poor formation consolidation and relatively viscose fluid, reservoirs may predictably produce massive amounts of sand and numerous troubles were found in the field as a result of sanding. No documented researches were found to introduce good parameters for rock strength and rock failure conditions through the field. Therefore, an accurate technique for predicting rock failure conditions may yield good profits and improve the economic returns through preventing sand production from the formations. General correlations were presented to accurately describe rock strength parameters for the field; the work utilizes the application of the wireline porosities to be used as a strength indicator through the combination of rock mechanical theories with the characterization of Fulla oilfield. Log porosities (density, sonic and neutron) were calibrated with the core measured porosity, and the best matching porosity were correlated with the dynamic calibrated strength parameters by different correlations. The results support the evidence of the use of porosity as an index for mechanical properties; power functions were found more reliable than the exponential functions, and can be used with a high degree of confidence; also it is more accurate than the Shale Index model presented in previous work for same field; however, the result does not support the direct linear expression presented in the literature for other field due to the variations in the field conditions.
The success of matrix acidizing in carbonates is often dependent on the efficiency of diversion agents, especially for treatments on wells with thick formations or multiple zones, or horizontal wells with long and heterogeneous intervals. Viscoelastic-surfactant (VES) -based self-diversion acid has been used successfully in fields because of its negligible damage to the formation and good diversion ability. Although the diversion ability of VES acid was studied experimentally with small core plugs, the diversion conditions of VES acid under in-situ radial conditions need to be studied. In this paper, we develop a VES radial-acidizing model that simulates VES acid flow, acid/rock reaction, porosity variation, viscosifying, wormholing, and acid diversion in multiple zones. On the basis of the model, extensive numerical simulations are conducted to investigate wormholing behavior of the VES acid, the factors that affect the diversion ability of VES acid, and the diversion conditions of VES acid. This study shows that the VES acid-dissolution patterns depend on the injection rate, and there is an optimum injection rate under which the dominant wormholes are formed. Compared with regular acid, the VES acid provides better acid placement for heterogeneous intervals. The intervals with separation shorter than approximately 150 m can be acidized together with VES acid if the two intervals have a close permeability with no perforation between them. The permeability ratio of the two intervals has remarkable influence on the diversion performance of VES acid. Even though the viscosified fluid acts as a temporary barrier to prevent the fluid flowing into the higher-permeability formation, the VES acid reduces diversion effectiveness for large permeability contrast. We also investigated the combined effect of permeability contrast and separation of the two intervals on diversion performance. This study provides a basis to select diversion technology and a method to evaluate diversion performance of VES acid for field-acidizing treatments.