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Abstract Uniformity of proppant distribution among multiple perforation clusters affects treatment efficiency in multistage fractured wells stimulated using the plug-and-perf technique. Multiple physical phenomena taking place in the well and perforation tunnels can cause uneven proppant distribution among multiple clusters. The problem has been studied in the recent years with experimental and computational fluid dynamics (CFD) methods, which provide useful insights but are impractical for routine designs. Simplified models that incorporated the proppant transport efficiency (PTE) correlation derived from the CFD results in a hydraulic fracture model have been also presented in literature. In this paper, we present a numerical model that simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, PTE, and dynamic pressure coupling with the hydraulic fractures. The model is efficient and is designed to be an independent wellbore transport model so it can be integrated with any fracture models, including fully 3D and/or complex fracture network models, for practical design optimization. The model predictions are compared and found to agree with previously published studies. Parametric studies demonstrate sensitivity of proppant distribution to grain size, fluid viscosity, and pumping rate for fixed perforation designs. Analysis of the simulation results shows that the dominant cause of uneven proppant distribution is proppant inertia. Possible slurry stratification is less important, except for the cases with relatively low flow rates and near toe clusters. Accordingly, proppant distribution is less sensitive to perforation phasing than to the number of perforations in clusters. Alterations of the number of perforations per cluster within a stage enable achieving more even proppant distribution.
Shahri, Mojtaba (Apache Corp.) | Tucker, Andrew (Apache Corp.) | Rice, Craig (Apache Corp.) | Lathrop, Zach (Apache Corp.) | Ratcliff, Dave (ResFrac) | McClure, Mark (ResFrac) | Fowler, Garrett (ResFrac)
Abstract In the last decade, we have observed major advancements in different modeling techniques for hydraulic fracturing propagation. Direct monitoring techniques such as fibre-optics can be used to calibrate these models and significantly enhance our understanding of subsurface processes. In this study, we present field monitoring observations indicating consistently oriented, planar fractures in an offset-well at different landing zones in the Permian basin. Frac hit counts, location, and timing statistics can be compiled from the data using offset wells at different distances and depths. The statistics can be used to calibrate a detailed three-dimensional fully coupled hydraulic fracturing and reservoir simulator. In addition to these high-level observations, detailed fibre signatures such as strain response during frac arrival to the monitoring well, post shut-in frac propagation and frac speed degradation with length can be modeled using the simulator for further calibration purposes. Application to frac modeling calibration is presented through different case studies. The simulator was used to directly generate the ‘waterfall plot’ output from the fibre-optic under a variety of scenarios. The history match to the large, detailed synthetic fibre dataset provided exceptional model calibration, enabling a detailed description of the fracture geometry, and a high-confidence estimation of key model parameters. The detailed synthetic fibre data generated by the simulator were remarkably consistent with the actual data. This indicates a good consistency with classical analytical fracture mechanics predictions and further confirm the interpretation of planar fracture propagation. This study shows how careful integration of offset-well fibre-optic measurements can provide detailed characterization of fracture geometry, growth rate, and physics. The result is a detailed picture of hydraulic fracture propagation in the Midland Basin. The comparison of the waterfall plot simulations and data indicate that hydraulic fractures can, in fact, be very well modeled as nearly-linear cracks (the ‘planar fracture modeling’ approach).
Abstract Well spacing and stimulation design are amongst the highest impact design variables which can dictate the economics of an unconventional development. The objective of this paper is to showcase a numerical simulation workflow, with emphasis on the hydraulic fracture simulation methodology, which optimizes well spacing and completion design simultaneously. The workflow is deployed using Cloud Computing functionality, a step-change over past simulation methods. Workflow showcased in this paper covers the whole cycle of 1) petrophysical and geomechanical modeling, 2) hydraulic fracture simulations and 3) reservoir simulation modeling, followed by 4) design optimization using advanced non-linear methods. The focus of this paper is to discuss the hydraulic fracture simulation methods which are an integral part of this workflow. The workflow is deployed on a dataset from a multi-well pad completed in late 2018 targeting two landing zones in the Vaca Muerta shale play. On calibrated petrophysical and geomechanical model, hydraulic fracture simulations are conducted to map the stimulated rock around the wellbores. Finely gridded base model is utilized to capture the property variation between layers to estimate fracture height. The 3d discrete fracture network (DFN) built for the acreage is utilized to pick the natural fracture characteristics of the layers intersected by the wellbores. The methodology highlights advances over the past modeling approaches by including the variation of discrete fracture network between layers. The hydraulic fracture model in conjunction with reservoir flow simulation is used for history matching the production data. On the history matched model, a design of experiments (DOE) simulation study is conducted to quantify the impact of a wide range of well spacing and stimulation design variables. These simulations are facilitated by the recent deployments of cloud computing. Cloud computing allows parallel running of hundreds of hydraulic fracturing and reservoir simulations, thereby allowing testing of many combinations of stimulation deigns and well spacing and reducing the effective run time from 3 months on a local machine to 1 week on the cloud. Output from the parallel simulations are fitted with a proxy model to finally select the well spacing and stimulation design variables that offer the minimum unit development cost i.e. capital cost-$ per EUR-bbl. The workflow illustrates that stimulation design and well spacing are interlinked to each other and need to be optimized simultaneously to maximize the economics of an unconventional asset. Using the workflow, the team identified development designs which increase EUR of a development area by 50-100% and reduce the unit development cost ($/bbl-EUR) by 10-30%.
Abstract Reducing well costs in unconventional development while maintaining or improving production continues to be important to the success of operators. Generally, the primary drivers for oil and gas production are treatment fluid volume, proppant mass, and the number of stages or intervals along the well. Increasing these variables typically results in increased costs, causing additional time and complexity to complete these larger designs. Simultaneously completing two wells using the same volumes, rates, and number of stages as for any previous single well, allows for more lateral length or volume completed per day. This paper presents the necessary developments and outcomes of a completion technique utilizing a single hydraulic fracturing spread to simultaneously stimulate two or more horizontal wells. The goal of this technique is to increase operational efficiency, lower completion cost, and reduce the time from permitting a well to production of that well—without negatively impacting the primary drivers of well performance. To date this technique has been successfully performed in both the Bakken and Permian basins in more than 200 wells, proving its success can translate to other unconventional fields and operations. Ultimately, over 200 wells were successfully completed simultaneously, resulting in a 45% increase in completion speed and significant decrease in completion costs, while still maintaining equivalent well performance. This type of simultaneous completion scenario continues to be implemented and improved upon to improve asset returns.
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.
Summary Mitigating the negative impact of fracture hits on production from parent and child wells is challenging. This work shows the impact of parent‐well depletion and repressurization on child‐well fracture propagation and parent‐well productivity. The goal of this study is to develop a method to better manage production/injection in the parent well so that the performance of the child well can be improved by minimizing fracture interference and fracture hits. A fully integrated equation‐of‐state compositional hydraulic fracturing and reservoir simulator has been developed to seamlessly model fluid production/injection (water or gas) in the parent well and model propagation of multiple fractures from the child well. The effects of drawdown rate and production time is presented for a typical shale play for three different fluid types: black oil, volatile oil, and dry gas. The results show that different reservoir fluids and drawdown strategies for the parent wells result in different stress distributions in the depleted zone, and this affects fracture propagation in the child well. Different strategies were studied to repressurize the parent well by varying the injected fluids (gas vs. water), the volumes of the preload fluid, and so on. It was found that fracture hits can be avoided if the fluid injection strategy is designed appropriately. In some poorly designed preloading strategies, fracture hits are still observed. Last, the impact of preloading on the parent‐well productivity was analyzed. When water was used for preloading, water blocking was observed in the reservoir, and it caused damage to the parent well. However, when gas was injected for preloading, the oil recovery from the parent well was observed to increase. Such simulations of parent–child well interactions provide much‐needed quantification to predict and mitigate the damage caused by depletion, fracture interference, and fracture hits.
Summary “Fracture hit” was initially coined to refer to the phenomenon of an infill-well fracture interacting with an adjacent well during the hydraulic-fracturing process. However, over time, its use has been extended to any type of well interference or interaction in unconventional reservoirs. In this study, an exhaustive literature survey was performed on fracture hits to identify key factors affecting the fracture hits and suggest different strategies to manage fracture hits. The impact of fracture hits is dictated by a complex interplay of petrophysical properties (high-permeability streaks, mineralogy, matrix permeability, natural fractures), geomechanical properties (near-field and far-field stresses, tensile strength, Young’s modulus, Poisson’s ratio), completion parameters (stage length, cluster spacing, pumping rate, fluid and proppant amount), and development decisions (well spacing, well scheduling, fracture sequencing). It is difficult to predict the impact of fracture hits, and they affect both parent and child wells. The impact on the child wells is predominantly negative, whereas the effect on parent wells can be either positive or negative. The “child wells” in this context refer to the wells drilled with pre-existing active/inactive well(s) around. The “parent well” refers to any well drilled without any pre-existing well around. Overall, fracture hits tend to negatively affect both the production and economics of lease development. The optimal approach rests in identifying the reservoir properties and accordingly making field-development decisions that minimize the negative impact of fracture hits. The different strategies proposed to minimize the negative impact of fracture hits are simultaneous lease development, thus avoiding parent/child wells (i.e., rolling-, tank-, and cube-development methods); repressuring or refracturing parent wells; using far-field diverters and high-permeability plugging agents in the child-well fracturing fluid; and optimizing stage and cluster spacing through modeling studies and field tests. Finally, the study concludes with a recommended approach to manage fracture hits. There is no silver bullet, and the problem of fracture hits in each shale play is unique, but by using the available data and published knowledge to understand how fractures propagate downhole, measures can be taken to minimize or even completely avoid fracture hits.
Mike Rainbolt is an experienced completions engineer and a senior technical advisor for Abra Controls. Mike sat down with Trent Jacobs to discuss some of the highlights from the 2020 Hydraulic Fracturing Technology Conference held recently in the Houston area. More than 3,500 petrotechnical professionals went to the conference which this year highlighted some major advances around the so-called parent-child issues that all US shale producers face. We hope you enjoy the SPE Podcast… and take away something useful to your job and career along the way. Your feedback is welcome, along with ideas for topics you would like to see us cover in future podcasts.
Chen, Ming (China University of Petroleum, China) | Zhang, Shicheng (China University of Petroleum, China) | Zhou, Tong (Research Institute of Petroleum Exploration and Development, Sinopec) | Ma, Xinfang (China University of Petroleum, China) | Zou, Yushi (China University of Petroleum, China)
Summary Creating uniform multiple fractures is a challenging task due to reservoir heterogeneity and stress shadow. Limited‐entry perforation and in‐stage diversion are commonly used to improve multifracture treatments. Many studies have investigated the mechanism of limited‐entry perforation for multifracture treatments, but relatively few have focused on the in‐stage diversion process. The design of in‐stage diversion is usually through trial and error because of the lack of a simulator. In this study, we present a fully coupled planar 2D multifracture model for simulating the in‐stage diversion process. The objective is to evaluate flux redistribution after diversion and optimize the dosage of diverters and diversion timing under different in‐stage in‐situ stress difference. Our model considers ball sealer allocation and solves flux redistribution after diversion through a fully coupled multifracture model. A supertimestepping explicit algorithm is adopted to solve the solid/fluid coupling equations efficiently. Multifracture fronts are captured by using tip asymptotes and an adaptive time‐marching approach. The modeling results are validated against analytical solutions for a plane-strain Khristianovic-Geertsma de Klerk (KGD) model. A series of numerical simulations are conducted to investigate the multifracture growth under different in‐stage diversion operations. Parametric studies reveal that the in‐stage in‐situ stress difference is a critical parameter for diversion designs. When the in‐situ stress difference is larger than 2 MPa, the fracture in the high‐stress zone can hardly be initiated before diversion for a general fracturing design. More ball sealers are required for the formations with higher in‐stage in‐situ stress difference. The diverting time should be earlier for formations with high in‐stage stress differences as well. Adding more perforation holes in the zone with higher in‐situ stress is recommended to achieve even flux distribution. The results of this study can help understand the multifracture growth mechanism during in‐stage diversion and optimize the diversion design timely.
Summary The primary objectives of perforating a lengthy cased‐and‐cemented wellbore section for fracture stimulation are to enable extensive communication with the reservoir and control the allocation of fluid and proppant into multiple intervals as efficiently as possible during fracturing treatments. Simultaneously treating multiple intervals reduces the number of fracture stages required, thus reducing treatment cost. One way to control the allocation is to use limited‐entry perforating. Execution and optimization of limited‐entry perforating requires awareness of the factors that can affect performance. This paper presents a case study of plug‐and‐perforate horizontal‐well treatments in an unconventional shale play in which various diagnostic methods were used to better understand these factors. Within the case study, three types of perforation‐evaluation diagnostics were implemented: injection step‐down tests and pressure analysis of the fracturing treatments, video‐based perforation imaging, and distributed acoustic sensing (DAS). Injection step‐down tests indicated that all perforations were initially accepting fluid. Surface‐pressure analysis of the main fracturing treatments indicated that in certain cases, several perforations were not accepting fluid and proppant (slurry) by the end of the job. Video‐based imaging indicated that a large majority of perforations showed unambiguous evidence of significant proppant entry. Evaluation of the erosion patterns on the perforations showed a positional bias where for a given fracture stage, perforations in clusters nearest the heel of the well were more eroded than perforations in clusters nearest the toe of the well. DAS analysis showed a positional bias, allocating more slurry volume to clusters nearest the heel of the well. However, DAS analysis also showed that changing the number of perforations in a cluster had a larger effect than the positional bias. The results of the case study indicated that a staggered perforation design using more gradual changes among clusters would lead to a more balanced treatment. This scenario was evaluated along with a job design featuring high excess perforation friction and an equal number of perforations in each cluster. Fracture‐simulation runs indicated that both tactics are likely to improve slurry allocation.