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Abstract During drilling oil, gas, or geothermal wells, the temperature difference between the formation and the drilling fluid will cause a temperature change around the borehole, which will influence the wellbore stresses. This effect on the stresses tends to cause wellbore instability in high temperature formations, which may lead to some problems such as formation break down, loss of circulation, and untrue kick. In this research, a numerical model is presented to simulate downhole temperature changes during circulation then simulate its effect on fracture pressure gradient based on thermo-poro-elasticity theory. This paper also describes an incident occurred during drilling a well in Gulf of Suez and the observations made during this incident. It also gives an analysis of these observations which led to a reasonable explanation of the cause of this incident. This paper shows that the fracture pressure decreases as the temperature of wellbore decreases, and vice versa. The research results could help in determining the suitable drilling fluid density in high-temperature wells. It also could help in understanding loss and gain phenomena in HT wells which may happen due to thermal effect. The thermal effect should be taken into consideration while preparing wellbore stability studies and choosing mud weight of deep wells, HPHT wells, deep water wells, or wells with depleted zones at high depths because cooling effect reduces the wellbore stresses and effective FG. Understanding and controlling cooling effect could help in controlling the reduction in effective FG and so avoid lost circulation and additional unnecessary casing points.
Al-Nakhli, Ayman R. (Saudi Aramco) | Tariq, Zeeshan (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals)
Abstract Commercial volumes of hydrocarbon production from tight unconventional reservoirs need massive hydraulic fracturing operations. Tight unconventional formations are typically located inside deep and over-pressured formations where the rock fracture pressure with slickwater becomes so high because of huge in situ stresses. Therefore, several lost potentials and failures were recorded because of high pumping pressure requirements and reservoir tightness. In this study, thermochemical fluids are introduced as a replacement for slickwater. These thermochemical fluids are capable of reducing the rock fracture pressure by generating micro-cracks and tiny fractures along with the main hydraulic fractures. Thermochemical upon reaction can generate heat and pressure simultaneously. In this study, several hydraulic fracturing experiments in the laboratory on different synthetic cement samples blocks were carried out. Cement blocks were made up of several combinations of cement and sand ratios to simulate real rock scenarios. Results showed that fracturing with thermochemical fluids can reduce the breakdown pressure of the cement blocks by 30%, while applied pressure was reduced up to 88%, when using thermochemical fluid, compared to slickwater. In basins with excessive tectonic stresses, the current invention can become an enabler to fracture and stimulate well stages which otherwise left untreated. A new methodology is developed to lower the breakdown pressure of such reservoirs, and enable fracturing. Keywords: Unconventional formation; breakdown pressure; thermochemicals; micro fractures.
Se, Yegor (Chevron ETC) | Sullivan, Michael (Chevron Canada) | Tohidi, Vahid (Chevron Canada) | Lazorek, Michael (Chevron Canada) | Attia, Ahmed (Ziebel US) | Chen, Phillip (Ziebel US) | Abbassi, Linda (Openfield Technology) | Schoepf, Virginie (Openfield Technology)
Abstract The well design with long lateral section and multistage frac completion has been proven effective for development of the unconventional reservoirs. Top-tier well production in unconventional reservoir can be achieved by optimizing hydraulic completion and stimulation design, which necessitates an understanding of flow behavior and hydrocarbon contribution allocation. Historically, conventional production logging (PL) surveys were scarcely used in unconventional reservoirs due to limited and often expensive conveyance options, as well as complicated and non-unique inflow interpretations caused by intricate and changing multiphase flow behavior (Prakash et al., 2008). The assessment of the cluster performance gradually shifted towards distributed acoustic (DAS) and temperature (DTS) sensing methods using fiber optics cable, which continuously gained popularity in the industry. Fiber optics measurements were anticipated to generate production profiles along the lateral with sub-cluster resolution to assist with optimal completions design selection. Encapsulation of the fiber in the carbon rod provided alternative conveyance method for retrievable DFO measurements, which gained popularity due to cost-efficiency and operational convenience (Gardner et al., 2015). Recent utilization of micro-sensor technology in PL tools, (Abbassi et al, 2018, Donovan et al, 2019) allowed dramatic reduction of the size and the weight of the PL toolstring without compromising wellbore coverage by sensor array. Such ultra-compact PL toolstring could utilize the carbon rod as a taxi and provide mutually beneficial and innovative surveillance combination to evaluate production profile in the unconventional reservoirs. Array holdup and velocity measurements across wellbore from PL would reveal more details regarding multi-phase flow behavior, which could be used for cross-validation and constraining of production inflow interpretation based on DFO measurements. This paper summarizes the lessons learned, key observations and best practices from the unique 4 well program, where such innovative combination was tested in gas rich Duvernay shale reservoir.
Grove, Brenden (Halliburton Jet Research Center) | McGregor, Jacob (Halliburton Jet Research Center) | DeHart, Rory (Halliburton Jet Research Center) | Dusterhoft, Ron (Halliburton) | Stegent, Neil (Halliburton) | Grader, Avrami (Ingrain, a Halliburton Service)
Abstract Hydraulically fractured completions dominate industry perforating activity, particularly in North American land basins. This has led to the development of fracture-optimized perforating systems in recent years. Aside from overarching safety, reliability, and efficiency priorities, the main technical performance attribute of these systems is consistent hole size in the casing, driven by limited entry fracture design considerations. While the industry continues to seek further improvements in hole size consistency, attention is also being directed to the perforations more holistically, from a perspective of maximizing the effectiveness of subsequent hydraulic fracturing and ultimately production operations. To this end, this paper presents two related activities addressing the development, qualification, and optimization of perf-for-frac systems. The first is a surface testing protocol used to characterize perforating system performance, in particular casing hole size and consistency. The second is a laboratory program, recently conducted to investigate perforating stressed Eagle Ford shale samples at downhole conditions. This program explored the influences of charge size, formation lamination direction, pore fluid, and dynamic underbalance on perforation characteristics. Casing hole size was also assessed. For the first activity (surface testing), we find that using cement-backed casing can be an important feature to ensure more downhole-realistic results. For the second activity (laboratory program), perforation casing hole sizes for the charges tested were in line with expectations based on existing surface test data, exhibiting negligible pressure dependency. Corresponding penetration depths into the stressed shale samples generally ranged from 3.5-in to 5-in, which is much shallower than might be expected based on surface concrete performance. Dynamic underbalance was found to exhibit some slight effect on the tunnel fill characteristics, while pore system fluid was found to have minimal influence on the results. An interesting feature of the perforated samples was the complex fracture network at the perforation tips, which appeared "propped" to some extent with charge liner debris. Some of these fractures were formation beds which had delaminated during the shot, a phenomenon observed for perforations both parallel and perpendicular to the laminations. The implications of these results to the downhole environment continues to be assessed. Of particular interest is the impact these phenomena might have on fracture initiation, formation breakdown, and treatment stages which accompany subsequent hydraulic fracturing pumping operations.
Abstract The application of high viscosity friction reducers (HVFRs) in unconventional plays has steadily increased over the past years, not only as alternatives to conventional friction reducers (FRs) but also as a direct replacement for the use of guar-based fluids. HVFRs demonstrate more efficient proppant transport, due to their unique rheological properties, concurrently with a high friction reduction effect allowing higher pumping rates. However, all these benefits come with few critical limitations related to frac water quality, compatibility with other additives, and static proppant suspension, which makes them very similar to conventional crosslinked gels regarding their Quality Assurance and Quality Control (QAQC) requirements at a well location during the field implementation. This paper illustrates the comprehensive laboratory efforts undertaken to evaluate different HVFR and crosslinked gel products, their successful field application supported by a robust and effective field QAQC process, and the critical importance of maintaining effective field-laboratory-field interaction/cycle to optimize the fluid design and maximize the results. Experimental studies on different products were conducted to measure the effect of frac water quality, HVFR loading, breaker loading, and compatibility with other additives used in the fluid recipe such as surfactants, scale inhibitors, and biocides. The ability of HVFR to suspend and transport proppant is not only a function of polymer loading but also highly influenced by fluid velocity as static and semi-dynamic proppant suspension tests demonstrate. Additionally, a full dynamic proppant transport test was also conducted using a multi-branched slot apparatus to simulate the flow inside a complex fracture network. Field execution followed a strict QAQC protocol including water analysis, field laboratory tests, water filtration, mixing procedure, product storage, and transport allowing direct onsite replication of the results that had been previously obtained in the laboratory. Constant communication between the field and the laboratory allowed a successful execution of several treatments in a challenging shale play in the Sichuan Region, China. These treatments achieved record proppant placements and, just as importantly, they demonstrated repeatability and consistency over time; which had not previously been attained. Laboratory testing proved critical in confirming that product segregation was occurring, even if there was no visual observation of this phenomenon, which had resulted in initial difficulties in fluid quality and reliability. The presence of constant QAQC engineering support on location was instrumental in rapidly identifying the potential root cause(s) and efficiently and correctly applying the necessary corrective actions. This paper will highlight the importance of laboratory testing, in order to design and optimize the fluid system. The paper will also demonstrate how critical the onsite QAQC is through actual examples of fluid optimization and field implementation. These two activities, although requiring a substantial resource commitment and effort, are both required to achieve successful execution.
Abstract Fracture growth in layered formations with depth-dependent properties has been a topic of interest amongst researchers because of its critical influence on well performance. This paper revisits some of the existing height-growth models and discusses the evaluation process of a new and modified model developed after incorporating additional constraints.The net-pressure is the primary driver behind fracture propagation and the pressure distribution in the fracture plays an important role in vertical propagation, as it supplies the necessary energy for fracture advancement in the presence of opposing forces. The workflow adopted for this study included developing a preliminary model that solves a system of non-linear equations iteratively to arrive at fracture height versus net pressure mapping. The theoretical results were then compared to those available in the literature. The solution set was then extended to a 100-layer model after incorporating additional constraints using superposition techniques.The predicted outcomes were finally compared to the fracture height observations made in the field on several treatments. A reasonable agreement between model-predicted and observed height was observed when a comparison between the two was made, for most cases.The majority of these treatments were pumped in vertical wells, at low injection rates of up to 8.0 bbl/min (0.021 m/s) where net pressures were intentionally restricted to 250 psi (1.72 MPa) in order to prevent fracture rotation to the horizontal plane.The leak-off was minimal given the low permeability formations. In some cases, however, the pumping parameters and fluid imparted pressure distribution appeared to dominate. Overall, it was apparent that for a slowly advancing fracture front, which is the case in low injection rate treatments, the fracture height could be predicted with reasonable accuracy. This condition could also be met in high rate treatments pumped down multiple perforation clusters such as in horizontal wells, though fracture-height measurement may not be as straightforward as in vertical wells. The model developed under the current study is suitable for vertical wells where fracture treatments are pumped at low injection rates. The solid-mechanics solution that is presented here is independent of pumping parameters and can be readily implemented to assist in selection of critical design parameters prior to the job, with a wide range of applicability worldwide.
Elsayed, Mahmoud (King Fahd University of Petroleum and Minerals) | El-Husseiny, Ammar (King Fahd University of Petroleum and Minerals (Corresponding author) | Kwak, Hyung (email: email@example.com)) | Hussaini, Syed Rizwanullah (Saudi Aramco) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals)
Summary In-situ evaluation of fracture tortuosity (i.e., pore geometry complexity and roughness) and preferential orientation is crucial for fluid flow simulation and production forecast in subsurface water and hydrocarbon reservoirs. This is particularly significant for naturally fractured reservoirs or postacid fracturing because of the strong permeability anisotropy. However, such downhole in-situ characterization remains a challenge. This study presents a new method for evaluating fracture tortuosity and preferential orientation based on the pulsed field gradient (PFG) nuclear magnetic resonance (NMR) technique. Such an approach provides diffusion tortuosity, τd, defined as the ratio of bulk fluid diffusion coefficient to the restricted diffusion coefficient in the porous media. In the PFG NMR technique, the magnetic field gradient can be applied in different directions, and therefore anisotropy in diffusion coefficient and τd can be evaluated. Three 3D printed samples, characterized by well controlled variable fracture tortuosity, one fractured sandstone, and three acidized carbonate samples with wormhole were used in this study. PFG NMR measurements were performed using both 2- and 12-MHz NMR instruments to obtain τd in the three different principal directions. The results obtained from the NMR measurements were compared with fracture tortuosity and preferential orientation determined from the microcomputed tomography (micro-CT) images of the samples. The results showed that τd increases as the fracture tortuosity and pore geometry complexity increases, showing good agreement with the image-based geometric tortuosity values. Moreover, the lowest τd values were found to coincide with the preferential direction of fracture surfaces and wormhole body for a given sample, whereas the maximum τd values correspond to the nonconnected pathway directions. These results suggest that the implantation of directional restricted diffusion measurements on the NMR well logging tools would offer a possibility of probing tortuosity and determining preferential fluid flow direction via direct downhole measurements.
Xie, Jun (Petrochina Southwest Oil and Gas Field Company) | Tang, Jizhou (Harvard University) | Sun, Sijie (Harvard University) | Li, Yuwei (Northeast Petroleum University) | Song, Yi (Petrochina Southwest Oil and Gas Field Company) | Huang, Haoyong (Petrochina Southwest Oil and Gas Field Company) | Pei, Hao (Harvard University) | Zhang, Fengshou (Tongji University)
Abstract Slurry, as a proppant-laden fluid for hydraulic fracturing, is pumped into initial perforated cracks to generate a conductive pathway for hydrocarbon movement. Recently, numerous studies have been done to investigate mechanisms of proppant transport within vertical fractures. However, the distribution of proppant during stimulation becomes much more complicated if bedding planes (BPs), natural fractures (NFs) or other discontinuities pervasively distributed throughout the formation. Thus, how to capture the transport and placement mechanisms of proppant particles in the opened BPs becomes a significant issue. In this paper, we propose a closed-form continuous proppant transport model based on the conservation of total proppant volume and sedimentation of proppant particles. This model enables to integrate with the fluid flow section of a 3-D hydro-mechanical coupled fracture propagation model and then predict the distribution of proppant velocity and slurry volume fraction within a dynamic fracture network. Stokes’ law is applied to determine the sedimentation velocity. In the fracture propagation model, rock deformation is governed by the analytical solution of penny-shaped crack to determine fracture width. Fluid flow is characterized by finite differentiation scheme and then the fluid velocity is obtained. These two parameters above are inputs for the proppant transport model and both slurry viscosity and density are updated in this step. Afterwards, both fracture width and fluid velocity would be altered in the fracture model. Analysis of the proppant distribution within crossing-shaped fracture is conducted to study mechanisms of proppant transport along opened BPs. From our numerical analysis, we find that the distribution of proppant concentration is independent with the fluid viscosity, but highly dependent on the volume fraction of pumping slurry, under a given pumping pressure. Due to the difference of viscosity and proppant volume fraction at locations of upper and lower BPs, we observe that two symmetric BPs are unevenly opened, with different channel length along BP. Moreover, the width of opened upper BP is much smaller than that of opened lower BP as a result of discrepancy of proppant sedimentation. Last but not the least, a criterion of flow bed mobilization is established for dynamically tracking the sedimentation along the BP. Then the effect of different parameters (such as proppant size, proppant density, fluid viscosity, injection rate) on proppant distribution along opened BPs is also studied. Our model fully considers the proppant transport and settlement, proppant bed formation and interaction between fracture and proppant, which helps to predict the influence of proppant during fracturing treatment. Additionally, our model is also capable of dynamically tracking the settlement of proppant along opened BPs.
Hou, Yanan (China University of Petroleum (Beijing)) | Peng, Yan (China University of Petroleum (Beijing) (Corresponding author) | Chen, Zhangxin (email: firstname.lastname@example.org)) | Liu, Yishan (University of Calgary and China University of Petroleum (Beijing) (Corresponding author) | Zhang, Guangqing (email: email@example.com)) | Ma, Zhixiao (China University of Petroleum (Beijing)) | Tian, Weibing (China University of Petroleum (Beijing))
Summary Pulsating hydraulic fracturing (PHF) is a promising fracturing technology for unconventional reservoirs because it could improve the hydraulic fracturing efficiency through inducing the fatigue failure of reservoir rocks. Understanding of the pressure wave propagation behavior in wellbores and fractures plays an important role in PHF optimization. In this paper, a transient flow model (TFM) was used to describe the physical process of pressure wave propagation induced by PHF, and this model was solved by the method of characteristics (MOC). Combination of the TFM and MOC was validated with experimental data. The impacts of controlling factors on the pressure wave propagation behavior were fully discussed, and these factors include the frequency of input loading, an injection mode, an injection position, and friction. More than 10,000 sets of pressure wave propagation behaviors in different scenarios were simulated, and their differences were illustrated. In addition, the generation mechanisms of different pressure wave propagation behaviors were explained by the Fourier transform theory and the vibration theory. The important finding is that there is resonance phenomenon in the propagation of the pressure wave, and the resonance frequencies are almost equal to the natural frequencies of a fluid column. As a consequence of resonance phenomenon, the amplitudes of bottomhole pressure (BHP) and fracture tip pressure will increase sharply when the input loading frequency is close to the resonance frequency and less than 5 Hz; otherwise, the resonance phenomenon will disappear. Furthermore, an injection mode can alter the resonance frequency and the amplitude and frequency of the induced pressure wave. In addition, a friction effect can significantly decrease both the resonance frequency and the resonance amplitude. These findings indicate that the optimized input loading frequency should be close to the natural frequency of a fracturing fluid in a wellbore to enhance its BHP.
Ju, Yang (China University of Mining and Technology (Corresponding author) | Wu, Guangjie (emails: firstname.lastname@example.org or email@example.com)) | Wang, Yongliang (China University of Mining and Technology) | Liu, Peng (China University of Mining and Technology) | Yang, Yongming (China University of Mining and Technology)
Summary In this paper, we introduce the entropy weight method (EWM) to establish a comprehensive evaluation model able to quantify the brittleness of reservoir rocks. Based on the evaluation model and using the adaptive finite element-discrete element (FE-DE) method, a 3D model is established to simulate and compare the propagation behavior of hydraulic fractures in different brittle and ductile reservoirs. A failure criterion combining the Mohr-Coulomb strength criterion and the Rankine tensile criterion is used to characterize the softening and yielding behavior of the fracture tip and the shear plastic failure behavior away from the crack tip during the propagation of a fracture. To understand the effects of rock brittleness and ductility on hydraulic fracture propagation more intuitively, two groups of ideal cases with a single failure mode are designed, and the fracture propagation characteristics are compared and analyzed. By combining natural rock core scenarios with single failure mode cases, a comprehensive evaluation index BIf for reservoir brittleness and ductility is constructed. The simulation experiment results indicate that fractures in brittle reservoirs tended to form a complex network. With enhanced ductility, the yielding and softening of reservoirs hamper fracture propagation, leading to the formation of a simple network, smaller fracture area (FA), larger fracture volume, and the need for higher initiation pressure. The comprehensive index BIf can be used to define brittleness or ductility as the dominant factor of fracturing behavior. That is, 0 < BIf ≤ 0.46 indicates that the reservoir has enhanced ductility and ductile fracturing prevails; 0.72 < BIf < 1 indicates that the reservoir has enhanced brittleness and brittle fracturing prevails; and 0.46 < BIf ≤ 0.72 means a transition from brittle to ductile fracturing. Based on fitting analysis results, the relationship between the calculated FAr and BIf is constructed to quantify the influence of reservoir brittleness and ductility on fracturing. The study provides new perspectives for designing, predicting, and optimizing the fracturing stimulation of tight reservoirs with various brittleness and ductility.