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Liu, Lijun (China University of Petroleum, East China) | Liu, Yongzan (Texas A&M University) | Yao, Jun (China University of Petroleum, East China) | Huang, Zhaoqin (China University of Petroleum, East China)
Significant conductivity losses of both propped hydraulic fractures and unpropped natural fractures are widely observed by laboratory experiments and field studies in shale-gas reservoirs. Previous studies have not well-considered the effects of dynamic fracture properties, which limit the accurate prediction of well performance and stress evolution. In this study, an efficient coupled flow and geomechanics model is proposed to characterize the dynamic fracture properties and examine their effects on well performance and stress evolution in complex fractured shale-gas reservoirs. In our proposed model, a unified compositional model with nonlinear transport mechanisms is used to accurately describe multiphase flow in shale formations. The embedded discrete fracture model (EDFM) is used to explicitly model the complex fracture networks. Different fracture constitutive models are implemented to describe the dynamic properties of hydraulic fractures and natural fractures, respectively. The finite-volume method (FVM) and finite-element method (FEM) are used for the space discretization of flow and geomechanics equations, respectively, and the coupled problem is solved by the fixed-stress split iterative method. The coupled model is validated against classical analytical solutions. After that, the proposed model is used to investigate the effects of hydraulic-fracture and natural-fracture properties on production behavior as well as pressure and stress evolution of shale-gas reservoirs. With the dynamic fracture properties incorporated, our model can predict the well production more accurately, and provide more realistic stress evolution that is essential for the design and optimization of refracturing and infill-well drilling.
Summary In a previous work, we introduced a three-parameter scaling solution that models the long-term recovery of dry gas from a hydrofractured horizontal well far from other wells and the boundaries of a shale reservoir with negligible sorption. Here, we extend this theory to account for the contribution of sorbed gas and apply the extended theory to the production histories of 8,942 dry-gas wells in the Marcellus Shale. Our approach is to integrate unstructured big data and physics-based modeling. We consider three adsorption cases that correspond to the minimum, median, and maximum of a set of measured Langmuir isotherms. We obtain data-driven, independent estimates of unstimulated shale permeability, spacing between hydrofractures, well-drainage area, optimal spacing between infill wells, and incremental gas recovery over a typical well life. All these estimates decrease to varying extents with increasing sorption. We find that the average well with median adsorption has a permeability of 250 nd, fracture spacing of 16 m, 30-year drainage length of 79 m, and a 30-year incremental recovery of 67%. Introduction Since 2012, the Marcellus Shale has been by far the most productive US shale play. Producing 25% of the total US dry natural gas, the Marcellus Shale currently produces at least three times more natural gas than any other major US shale play, including, in order of decreasing production, the Permian, Haynesville, Utica, Eagle Ford, Barnett, Woodford, Fayetteville, and Antrim shales (Figure 1). This high productivity has attracted significant attention from developers. The majority of drilling activities have taken place in two sweet spots: northeastern Pennsylvania, which primarily contains dry gas, and southwestern Pennsylvania and northern West Virginia, which produce liquid-rich gas (Popova 2017). Since leading US shale-gas production for the first time in 2012, the Marcellus Shale currently produces three times more than the Permian Basin, the runner-up shale-gas producer. Given how important Marcellus is to the US economy and energy security, it seems worthwhile to comb through the available production data and attempt to extract key information from the wells that are active and productive.
Polymers are used to viscosify the fluid. Crosslinkers are used to change the viscous fluid to a pseudoplastic fluid. Biocides are used to kill bacteria in the mix water. Buffers are used to control the pH of the fracture fluid. Surfactants are used to lower the surface tension. Fluid-loss additives are used to minimize fluid leakoff into the formation. Stabilizers are used to keep the fluid viscous at high temperature. Breakers are used to break the polymers and crosslink sites at low temperature.
Montgomery, Carl T. (NSI Technologies L.L.C.) | Smith, Michael B. (NSI Technologies L.L.C.) | An, Zhongfeng (NSI Technologies L.L.C.) | Klein, Hank H. (HK Technologies) | Strobel, William (Zeeospheres Ceramics Inc) | Myers, Roger R. (RRM Completions, LLC.)
Providing and sustaining fracture conductivity in secondary fracture systems created during the stimulation of very tight unconventional shale plays is critical for sustaining productivity and reducing decline rates. In this paper, a discrete fracture network model which includes proppant transport will be utilized to show the effect that an unsupported vs supported dilated fracture network has on the decline and ultimate recovery of available resources in shale. In addition, the characteristics and properties of a microproppant will be described. The physical properties of the material, the oil and water conductivity of the proppant at various fracture widths along with the resultant Fcd will be presented. Utilizing a bridging factor of 3, a comparison of the surface area propped by various proppants will be made. The proppant transport characteristics will also be described. The production benefits of utilizing very small proppants will be demonstrated utilizing production data from four different rock systems including the Barnett, Woodford, Utica, Permian Basin and Marcellus shale. Several additional operational benefits including reduced pumping pressures and far field diversion to prevent fracture hits will also be discussed. Finally, operational considerations will be described including utilizing liquid slurry's, pump wear evaluations and recommended proppant addition points will be described.
McClure, Mark (ResFrac Corporation) | Picone, Matteo (ResFrac Corporation) | Fowler, Garrett (ResFrac Corporation) | Ratcliff, Dave (ResFrac Corporation) | Kang, Charles (ResFrac Corporation) | Medam, Soma (ResFrac Corporation) | Frantz, Joe (ResFrac Corporation)
Hydraulic fracturing and reservoir simulation are used by operators in shale to optimize design parameters such as well spacing, cluster spacing, and injection schedule. In this paper, we address'freqently asked questions' that we encounter when working on hydraulic fracture modeling projects with operators. First, we discuss three high-level topics: (1) data-driven and physics-based models, (2) the modeling workflow, and (3) planar-fracture modeling versus'complex fracture network' modeling. Next, we address specific technical topics related to modeling and the overall physics of hydraulic fracturing: (1) interrelationships between cluster spacing and other design parameters, (2) processes affecting fracture size, (3) fracture symmetry/asymmetry, (4) proppant settling versus trapping, (5) applications of Rate-Transient Analysis (RTA), (6) net pressure matching, (7) Initial Shut-In Pressure (ISIP) trends along the wellbore, and (8) the effect of understressed/underpressured layers. We discuss practical modeling decisions in the context of field observations.
Liang, Feng (Aramco Services Company: Aramco Research Center—Houston) | Han, Yanhui (Aramco Services Company: Aramco Research Center—Houston) | Liu, Hui-Hai (Aramco Services Company: Aramco Research Center—Houston) | Saini, Rajesh (Aramco Services Company: Aramco Research Center—Houston) | Rueda, Jose I. (Saudi Aramco)
Hydraulic fracturing has been widely used in stimulating tight carbonate reservoirs to improve oil and gas production. Improving and maintaining the connectivity between the natural and induced microfractures in the far-field and the primary fracture networks are essential to enhancing the well production rate because these natural and induced unpropped microfractures tend to close after the release of hydraulic pressure during production. This paper provides a conceptual approach for an improved hydraulic fracturing treatment to enhance the well productivity by minimizing the closure of the microfractures in tight carbonate reservoirs and enlarging the fracture aperture.
The proposed improved fracturing treatment was to use the mixture of the delayed acid-generating materials along with microproppants in the pad/prepad fluids during the engineering process. The microproppants were used to support the opening of natural or newly induced microfractures. The delayed acid-generating materials were used in this strategy to enlarge the flow pathways within microfractures owing to degradation introduced under elevated temperatures and interaction with the calcite formation.
The feasibility of the proposed approach is evaluated by a series of the proof-of-concept laboratory coreflood experiments and numerical modeling results. First, one series of experiments (Experiments 1–3) was designed to investigate the depth of the voids on the fracture surface generated by the solid delayed acid-generating materials under different flow rates of the treatment fluids and different temperatures. This set of tests was conducted on a core plug assembly that was composed of half-core Eagle Ford Sample, half-core hastelloy core plug, and a mixture of solid delayed acid-generating materials [polyglycolic acid (PGA)] along with small-sized proppants sandwiched by two half-cores. Surface profilometer was used to quantify the surface-etched profile before and after coreflood experiments. Test results have shown that PGA materials were able to create voids or dimples on the fracture faces by their degradation under elevated temperature and the chemical reaction between the generated weak acid and the calcite-rich formation. The depth of the voids generated is related to the treatment temperature and the flow rate of the treatment fluids. Experiment 4 was conducted using two half-core splits to quantify the improvement factor of the core permeability due to the treatment with mixed sand and PGA materials.
Simulations of fluid flow through proppant assembly (inside of the microfractures) using the discrete element method (DEM)–lattice Boltzmann method (LBM) coupling approach for three different scenarios (14 cases in total) were further conducted to evaluate the fracture permeability and conductivity changes under different situations such as various gaps between proppant particulates and different depths of voids generated on fracture faces: (1) fluid flow in a microfracture without proppant, (2) fluid flow in a microfracture with small-sized proppants, and (3) fluid flow in a microfracture supported by small-sized proppants and generated voids on the fracture walls. The simulation results show that with proppant support (Scenario 2), the microfracture permeability can be increased by tens to hundreds of times in comparison to Scenario 1, depending on the gaps between proppant particles. The permeability of proppant-supported microfracture (Scenario 3) can be further enhanced by the cavities created by the reactions between the generated acid and calcite formation.
This work provides experimental evidence that using the mixture of the solid delayed acid-generating materials along with microproppants or small-sized proppants in stimulating tight carbonate reservoirs in the pad/prepad fluids during the engineering process may be able to effectively improve and sustain permeability of flow pathways from microfractures (either natural or induced). These findings will be beneficial to the development of an improved hydraulic fracturing treatment for stimulating tight organic-rich carbonate reservoirs.
Reuse of flowback water in hydraulic fracturing is usually used by industry to reduce consumption, transportation, and disposal cost of water. However, because of complex interactions between injected water and reservoir rocks, induced fractures may be blocked by impurities carried by flowback and mineral precipitation by water/rock interactions, which causes formation damage. Therefore, knowledge of flowback water/rock interactions is important to understand the changes within the formation and effects on hydraulic fracturing performance.
This study focuses on investigating flowback water/rock interactions during hydraulic fracturing in Marcellus Shale. Simple deionized water (DI)/rock interactions and complicated flowback water/rock interactions were studied under static and dynamic conditions. In static experiments, crushed reservoir rock samples were exposed to water for 3 weeks at room condition. In the dynamic experiment, continuous water flow interacted with rock samples through the coreflooding experimental system for 3 hours at reservoir condition. Before and after experiments, rock samples were characterized to determine the change on the rock surfaces. Water samples were analyzed to estimate the particle precipitation tendency and potential to modify flow pathway.
Surface elemental concentrations, mineralogy, and scanning electron microscope (SEM) images of rock samples were characterized. Ion contents, particle size, total dissolved solids (TDS), and zeta-potential in the water samples were analyzed. After flowback water/rock interaction, the surface of the rock sample shows changes in the compositions and more particle attachment. In produced water, Na, Sr, and Cl concentrations are extremely high because of flowback water contamination. Water parameters show that produced water has the highest precipitation tendency relative to all water samples. Therefore, if flowback water without any treatment is reused in hydraulic fracturing, formation damage is more likely to occur from blockage of pores.
Flowback water management is becoming very important due to volumes produced in every hydraulic fracturing operation. Deep well injection is no longer a favorable option because it results in disposal of high volumes of water that cannot be used for other purposes. A second option is the reuse of waste water for fracturing purposes, which reduces freshwater use significantly. However, the impurities present in flowback water may deteriorate the fracturing job and reduce or block the hydraulic fracturing apertures. This study shows that a simple filtration process applied to the flowback water allows for reinjection of the flowback water without further complication to the water/rock interaction, and does not cause significant formation damage in the fractures.
Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Britt, Larry K. (NSI Fracturing) | Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Al-Attar, Atheer M. (Enterprise Products) | Trevino, Al-Hameedi (Missouri University of Science and Technology) | Al-Bazzaz, Waleed H. (Kuwait Institute for Scientific Research)
Drilling, completion, and stimulation designs have changed over time as a result of the oil and gas industry's ongoing efforts to increase well productivity. Over the last five years hydraulic fracturing treatments, represented by the volume of pumped water and the amount of proppant utilized, have increased significantly, along with the lengths of horizontal wells. This work represents a large-scale descriptive analysis study to illustrate the trends and the range of completion, stimulation and production parameters in the Marcellus Shale play of the Appalachian Basin between 2012 and the last quarter of 2017 (2012-2018).
A database was created by combing stimulation fluids and proppant data from the FracFocus 3.0 chemical registry, with completion and production data from the DrillingInfo database. More than 2000 Marcellus Shale wells were utilized in this study. The data were processed and cleaned from outliers. Box plots and distribution bar charts are presented for most of the parameters in this study, to show the range in values for each parameter and its frequency of use. The stimulation parameters were normalized to perforated lateral length in order to compare productivity between the wells.
Trends identified in this study show how operators in the Marcellus have increased the use of hybrid fracturing fluids, in addition to increasing water and proppant volumes over time. The work also illustrates the point at which increasing fracture treatment volumes no longer increases production rate.
This paper demonstrates the utility of integrating publicly available databases to examine well completion trends in the Marcellus. The work also provides a summary of well response as a function of treatment volume over the five year study period.
Li, Shuai (Research Institute of Petroleum Exploration and Development, PetroChina) | Wang, Xin (Research Institute of Petroleum Exploration and Development, PetroChina) | He, Chunming (Research Institute of Petroleum Exploration and Development, PetroChina) | Liang, Tiancheng (Research Institute of Petroleum Exploration and Development, PetroChina) | Fu, Haifeng (Research Institute of Petroleum Exploration and Development, PetroChina)
The concept of stimulated reservoir volume (SRV) has conquered the whole oil and gas industry after it was firstly put forward by Fisher et al. in 2004. This concept was used to provide a visual display of hydraulic fracturing performance based on the monitored microseismic data, and had played very important roles in evaluating the stimulation effectiveness, while at the same time, accompanied with numerous queries and criticisms.
In this paper, we firstly carried out large-scale rock block experiments (the rock block size is 1m×1m×1m) under the in-situ stress condition to simulate the whole process of hydraulic fracturing, and during the period, we use acoustic emission (AE) monitoring method to obtain the fracture propagation events. Via the indoor experiment, we want to show the corresponding relationship between SRV events (obtained via AE monitoring) and artificial fracture propagation (obtained via fluorescence irradiate of cut rocks after experiment). Secondly, we carried out series of numerical reservoir simulation, fracture propagation simulation and well testing analysis to history match the experimental data and field production data, aiming to reveal the applicability of SRV concept in tight or shale reservoirs.
Results showed that fracture propagation is a competition controlled by stresses and rock fabric. The propagation of the hydraulic fracture is generally perpendicular to the minimum principal stress while is locally controlled by the rock fabric. Rock fabric will directly affect the fracture propagation including the bedding development, the interface bonding strength, the bedding fracture toughness and the bedding longitudinal stress difference. A large amount of acoustic emission events were obtained on rock sample's horizontal bedding position, not only along the vertical artificial cracks, and this may result in low correlation of the actual SRV events with the later well production. After the experiments, we cut the large rock block into three small parts and fluorescence irradiated, we found that the main fracture propagation has crossed some rock beddings, while still controlled by the bedding, and finally expanded along the bedding.
SRV events obtained in beddings or other discontinuous surfaces have less contribution to well production, and totally believe in SRV concept or SRV clouds may be a misleading to the evaluation of well performance.
Ren, Long (Xi'an Shiyou University) | Zhan, Shiyuan (Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Zhou, Desheng (University of Alberta) | Su, Yuliang (China University of Petroleum, East China) | Wang, Wendong (Xi'an Shiyou University) | Chen, Mingqiang (Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Jing, Cheng (China University of Petroleum, East China) | Sun, Jian (China University of Petroleum, East China) | Tang, Kang (Xi'an Shiyou University)
Multiple hydraulic fractures in naturally fractured unconventional oil reservoirs have often induced complex fracture network growth, as revealed by microseismic monitoring data by Maxwell et al. (2002), Fisher et al. (2005) and Daniels et al. (2007). History matching and production forecasting from an unconventional oil reservoir is possible only if a complex fracture network can be clearly described through the engineering parameters. However, currently, the integration technology of propagation simulation and structural characterization of the complex fracture network is still an extreme challenge. A new propagation modeling and characterization technique has been developed for these complex fracture network expansion that combines improved displacement discontinuity method (DDM) and pseudo-3D fracture propagation model to simulate the propagation process of complex fracture network and improve stimulation accuracy. This is very important for modeling and simulation of multi-fracture propagation in a unconventional oil reservoir with natural fractures. The theoretical model include the calculation model of combined stress field, the mechanical model of fracture propagation patterns and the corresponding propagation criteria, the injection fluid distribution model, and the mathematical model for structural description and morphological characterization as a post-processing program. The propagation simulation results of complex fracture network are implicitly and directly entered into the post-processing program and characterized by some engineering parameters as well. Simulation results show that the different propagation patterns of fracture network are produced, which is governed by the in-situ stress anisotropy, hydraulic fracture density, and distribution modes of preexisting natural fracture as well as fractures interaction angle.