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Abstract In this case study, we apply a novel fracture imaging and interpretation workflow to take a systematic look at hydraulic fractures captured during thorugh fracture coring at the Hydraulic Fracturing Test Site (HFTS) in Midland Basin. Digital fracture maps rendered using high resolution 3D laser scans are analyzed for fracture morphology and roughness. Analysis of hydraulic fracture faces show that the roughness varies systematically in clusters with average cluster separation of approximately 20' along the core. While isolated smooth hydraulic fractures are observed in the dataset, very rough fractures are found to be accompanied by proximal smoother fractures. Roughness distribution also helps understand the effect of stresses on fracture distribution. Locally, fracture roughness seems to vary with fracture orientations indicating possible inter-fracture stress effects. At the scale of stage lengths however, we see evidence of inter-stage stress effects. We also observe fracture morphology being strongly driven by rock properties and changes in lithology. Identified proppant distribution along the cored interval is also correlated with roughness variations and we observe strong positive correlation between proppant concentrations and fracture roughness at the local scale. Finally, based on the observed distribution of hydraulic fracture properties, we propose a conceptual spatio-temporal model of fracture propagation which can help explain the hydraulic fracture roughness distribution and ties in other observations as well.
Apache found something positive to say about its huge gas-producing play in the Permian at a time when gas is selling at rock-bottom prices. When it shut in a 14-well pad on its Alpine High play for 60 days, gas and condensate production surged. It was a rare test of whether a production break can allow water in rock near the fracture face to soak in deeper, allowing gas and liquids to flow more freely. "The gas rate came back above the pre-soak rate and it's actually holding in pretty flat, so it shows there was some impact and the condensate rate came in higher than the pre-soak rate," said Dave Pursell, executive vice president of planning, reserves and fundamentals, during the company's third quarter earnings call. The wells were on the huge Blackfoot pad, which Apache had highlighted a year ago as a major test of the industry trend toward concentrating many wells at a single location to reduce development costs.
Abstract Formation and fracture damage coupled with condensate blockage might significantly reduce the productivity of the hydraulically fractured gas condensate wells. Implicit numerical representation of a hydraulic fracture oversimplifies and disables distinction of individual physically occurring mechanisms causing the well deliverability loss. In this paper, more realistic analysis of production impairment is presented by explicit fracture modelling using an in-house tool. The objective is identification and ranking of the main factors and flow characteristics contributing to productivity drop. The in-house tool can be characterized as an interface between a fracture design modelling software and a reservoir simulator. An accurate fracture geometry and spatial property mapping is incorporated into a reservoir model via local grid refinement (LGR) generation. An additional functionality of the in-house tool also allowed, based on the fracture report, to determine the initial distribution of the leak-off fluid around the fracture. A mechanically induced damage zone surrounding the fracture was reproduced by permeability/porosity reduction or transmissibility modification on the boundary between the matrix and fracture interface. Permeability modification along with stress-dependent transmissibility option were used to represent the damage of proppant pack on fracture gridblocks. Explicit and comprehensive numerical representation of the near fracture flow performance was first implemented in a synthetic model. The conducted study revealed that the damage both inside the fracture and in the formation accelerates and enhances the condensate blockage effect. High-velocity capillary number effect within the fracture masked the negative contribution of liquid drop-out on relative permeability curves and can also overwhelm the turbulent non-Darcy flow impact. To validate the observed phenomena a single well reservoir sector model with explicit hydraulic fracture representation was calibrated against the real production data. Adequate history match of the measured BHP was only possible with dramatic fracture and formation permeability reduction to account for damage processes. Condensate blockage effect caused more than 50% loss of gas flow rate.
Karazincir, Oya (Chevron Corporation) | Li, Yan (Chevron Corporation) | Williams, Wade (Chevron Corporation) | Zaki, Karim (Chevron Corporation) | Rijken, Peggy (Chevron Corporation) | Rickards, Allan (Proptester Labs)
Acid stimulation is a common remedial practice for formations that produce below the target production rates. Acid stimulation can be performed during the early-life of a well, soon after the well is put on production, or more typically, following a production period once production rates have started to decline. Often, acid treatments are repeated multiple times during the producing life of a well, as restimulation becomes necessary. Sandstone acid systems can contain organic acids and/or hydrochloric acid, HCl, to target damage caused by carbonate solids, inorganic scaling, residual gel from fracturing operations or fluid loss control events, while hydrofluoric acid, HF, is used for siliceous damage/fines removal, mainly from and around the proppant pack in a hydraulically fractured formation. In a fractured formation, the acid sequence will first penetrate the least resistant zones, i.e. the fracture, and leak into the fracture face. For a propped fracture, proppant embedment at the fracture formation face naturally occurs under closure stress and increases with depletion.
A test program was designed to evaluate the effect of remedial acidizing practices on proppant embedment, frac face damage and reduction in porosity and permeability of the formation in these zones. A test method that can directly measure fracture-face permeability in parallel to fracture conductivity has been used to measure acid exposed fracture face permeability and proppant pack conductivity under depletion conditions. Initial tests were conducted in intermediate permeability, medium strength sandstone rock where baseline proppant conductivity and fracture face permeability were established with synthetic brine flow. Next, a remedial acid system was injected into the fracture and was allowed to leak-off into the fracture face. Following a shut-in period, brine was flowed back across the core platen representing the formation and the permeability of the core was tracked as a function of time under constant stress. Proppant pack permeability was also measured with brine flow along the fracture. The acidizing, shut-in and flow-back sequence was repeated three times to measure the impact of multiple acidizing treatments on proppant embedment, frac face damage and permeability loss. A similar test was conducted with five sequences of acid injection for comparison. Post-test analysis was conducted to study frac face damage, depth of proppant embedment and damage zone, rock strength and presence of fines in pore space. Test results were compared to those conducted with unacidized core.
The impact of repetitive acidizing practices on stimulation at the fracture face and on proppant embedment was investigated using the modified Frac Face Damage (FFD) test set-up, a test system that was introduced in earlier studies. At constant closure stress, FFD tests with acid injection can show permeability increase, followed by a decline in permeability. Current results suggest rate of permeability decline might accelerate after multiple acid treatments. Post-test analysis of the fracture face core has been conducted to evaluate the cause of the permeability reduction. Scanning Electron Microscopy (SEM) analysis show dissolved core material and fines being carried into the fracture face with one test. Micro CT-scan analysis is used to track porosity reduction at the fracture face. UCS and triaxial measurements are conducted to compare the change in the rock strength to that of the unacidized core. Thin section analysis of the fracture face core shows wide-spread grain crushing that penetrate deeper into the fracture face compared to unacidized core material tested with the same equipment.
A coupled peridynamics and finite-volume based poroelastic hydraulic fracturing simulator is applied to study failure mechanisms around hydraulic fractures. Primary mechanisms are identified that result in the creation of the SRV, which include the failure of mineral grain boundaries at the pore scale and reactivation of the natural fractures. The poroelastic stress changes due to fluid injection into a hydraulic fracture relax the stresses around the mineral interfaces and natural fractures, thereby promoting their failure. The magnitude of the strain (determined by the fracture width) controls the spatial extent of the SRV. More failure is observed closer to the hydraulic fracture. Failure regions like these form the SRV and their distance from the fracture face provides an estimate of the spatial extent of the SRV. A formation with a lower Young modulus transmits stress changes farther and forms a bigger SRV. Moreover, in a gas reservoir, due to the high compressibility of the gas, the changes in reservoir pressure and thus the poroelastic stresses are localized near the hydraulic fracture, resulting in a smaller SRV extent than an oil reservoir. 1. INTRODUCTION A propagating hydraulic fracture results in the creation of a stimulated rock volume (SRV), a region of higher permeability, around the hydraulic fracture (Mayerhofer et al., 2010). The effectiveness of a fracturing treatment is often correlated with the SRV extent and its permeability. These parameters are commonly obtained using microseismic or flowback data. Microseismic events generated during fracturing are received by the array of geophones installed in the vicinity (Zimmer, 2011). Flowback monitoring involves the analysis of early production data, comprising of the produced fracturing fluid (Clarkson & Williams-Kovacs, 2013; Alkouh et al., 2013). In this paper, we develop a novel modeling workflow for estimating the SRV extent using our integrated Peridynamics (PD)-Finite Volume (FV) based hydraulic fracturing model (Agrawal et al., 2020; Agrawal & Sharma, 2020). We propagate a hydraulic fracture using the FV formulation and monitor the resulting remote material damage using the PD formulation. The propagating hydraulic fracture causes poroelastic stress changes around it, which may lead to shear failure of the surrounding natural fractures or that of the weak mineral interfaces. In the case of unconventional reservoirs, these shear failure cracks may undergo sufficient permeability enhancement to allow for the flow of reservoir fluids in an otherwise virtually impermeable rock matrix. This region of enhanced permeability around the main hydraulic fracture constitutes the SRV.
Apache found something positive to say about its huge gas-producing play in the Permian at a time when gas is selling at rock-bottom prices. When it shut in a 14-well pad on its Alpine High play for 60 days, gas and condensate production surged. It was a rare test of whether a production break can allow water in rock near the fracture face to soak in deeper, allowing gas and liquids to flow more freely. “The gas rate came back above the pre-soak rate and it’s actually holding in pretty flat, so it shows there was some impact and the condensate rate came in higher than the pre-soak rate,” said Dave Pursell, executive vice president of planning, reserves and fundamentals, during the company’s third quarter earnings call. The wells were on the huge Blackfoot pad, which Apache had highlighted a year ago as a major test of the industry trend toward concentrating many wells at a single location to reduce development costs. In mid-2018, the company said the pad was producing 99 mm ft/d, and 200 B/D of oil from 12 wells. Based on the comment during the call, production since then has been disappointing. “We thought, let’s take advantage of low commodity prices and initiate a 60-day soak to really understand whether it is a relative permeability issue or what is the mechanism for the underperformance,” Pursell said. The price of doing the test was a significant decline in Alpine High production—Apache said the shut-in was a prime reason for a 30% drop in production there. But with gas prices so low, the expected upside apparently justifies the revenue delayed. During that earnings call, Apache also said it would reduce the number of rigs working in the Alpine High play from five to two so it could concentrate on Permian Basin acreage. Stories about the benefits of soaking have been around for a long time. As has talks about its downsides. In those cases, production was not an option, often due to lack of pipeline access or processing facilities. Apache tried soaking on the big pad because, “a significant amount of water was pumped into a small area of the reservoir, which may have impacted well productivity,” Pursell said. To answer that question and others, Pursell said Apache has “a team of folks working on the Blackfoot and all the multiwell pads we drilled and completed to date.” Is It Worth It? Apache is getting in the middle of an argument over whether soaking is worth the production days lost. While it often does cause a production spurt, the gains can quickly fade and skeptics argue that soaking can cause clay-rich rocks to swell, causing damage. Robert Hawkes, general manager at Abra in Canada and an SPE Distinguished Lecturer, has long advocated soaking. He said the industry needs to realize that water’s impact goes beyond fracturing rock and delivering sand to prop fractures.
In this paper, we introduce a novel fracture imaging method which uses high resolution 3D laser scanning to develop detailed surface maps of the core fracture faces. The digital maps are then used to analyze fracture surface characteristics wherein observed variations provide us with meaningful insights into the fractures. We share a mathematical approach for roughness evaluation to identify morphological properties for individual fractures within rock samples. The approach is tested on core extracted at the Hydraulic Fracturing Test Site (HFTS - 1) in the Permian Basin. We characterize the roughness variations with depth across the cored section. In addition, we compare results obtained previously from core sampling and analysis to demonstrate that proppant entrapment observed within the cored interval is strongly correlated with the changes in fracture morphology. We also use calculated roughness along with the the changing behavior of roughness radially away from the center of fracture faces to predict roughness "types" such as propagational features or textural roughness characteristics. Based on the specific fracture characterization work shared here as well as other potential uses, our paper highlights significant advantages such scanning and digital imaging of fractures may have over traditional cataloging using photographic imaging. Furthermore, as demonstrated in this study, data sampled from these detailed maps can be used to further characterize and analyze these features in a more systematic and robust manner when compared with the more traditional geological analysis of cores.
Zipper fracturing is a method of sequencing frac jobs in multi-well pads that helps increase operational efficiency and reduce stimulation time for a pad. This technique involves stimulating several wells in a pad in a prescribed sequence of stages. In this work, we provide a thorough assessment of the various factors impacting the effectiveness of zipper fracturing treatments and provide a methodology for selecting an optimum sequence of fracture stages.
A fully implicit, parallelized, 3-D, pad-scale reservoir-fracturing simulator is used to simulate the dynamic propagation of multiple, non-planar fractures from multiple treatment wells while capturing the stress interference between fractures. This interference is captured both on an intra-well as well as an inter-well scale. Interaction between fractures propagating from different wells is found to be dependent on pad design, completion design, and reservoir parameters. We evaluate the effectiveness of the stimulation operation by comparing the impact of operation decisions on the created fracture geometries and simulated productivity of the propagated fractures using seamless fracturing-reservoir simulations.
The simulation results are used to understand the impact of well spacing, stage spacing, staggering of zipper-frac wells, lagging of stages during zipper fracturing, size of the frac job, stress contrast in the reservoir and rock properties. Using multi-cluster fracturing simulations and accurate proppant distribution calculations in the wellbore, we consider the impact of various operational decisions mentioned above on the distribution of proppant in the created fractures. We observe that fracture closure during shut-in of a stage impacts the created fracture geometries. This affects the proppant distribution in the fractured stages. The impact of the operational decisions on the fracture conductivity degradation during stimulation is also captured using seamless fracture-reservoir simulations. We show that the results obtained from these simulations can help design pad-scale operations to maximize the fracture-reservoir contact area or improve the productivity of the wells.
In this work, for the first time, we assess the impact of zipper fracturing on well productivity by performing coupled fracturing-reservoir simulations. The software is used to simulate fracture propagation and fracture closure during shut-in and production. The results obtained from these simulations recommend an optimized fracture sequencing, stage lag and staggering strategy to maximize the productivity of the pad.
Naik, Sarvesh (Chevron Energy Technology Company) | Dean, Mark (Saudi Arabian Chevron) | McDuff, Darren (Chevron Energy Technology Company) | Ranson, Andrew (Saudi Arabian Chevron) | Jin, Xiao (Texas A&M University) | Zhu, Ding (Texas A&M University) | Hill, Alfred Dan (Texas A&M University)
Saudi Arabian Chevron (SAC) partnered with the Texas A&M University Petroleum Engineering Department and Reservoir Productivity Geomechanics Team of Chevron's Energy Technology Center (ETC) to perform acid fracturing conductivity tests on the Ratawi Limestone core samples. These tests were also performed on an analog limestone from an onshore USA field and Indiana Limestone samples for comparison with the results from the Ratawi Limestone samples. This paper shows the results of the acid fracture conductivity tests using various acid treatment systems on three different limestone formations and compares the acid etching and conductivity responses between homogeneous and heterogeneous mineralogy.
The success of acid fracturing treatment depends on the creation and sustainability of fracture conductivity under reservoir conditions. The fracture conductivity depends on the reservoir rock & acid reactivity, acid-etched pattern, closure stress on the fracture face and the pore pressure depletion.
Laboratory testing shows that acid fracturing is a viable option for large-scale development of the Ratawi Limestone. Its heterogeneous mineralogy plays an important role for sustaining the fracture conductivity after acid injection. Composed primarily of calcite and dolomite, limestone dissolves positively in acid. However, the insoluble minerals, such as the clay streaks with higher mechanical properties, acted as pillars to partially prop the fractures open as closure stress was applied. Essentially, the heterogeneous mineralogy of this formation assists with sustaining fracture conductivity as the reservoir pressure depletes.
Wang, Junlei (Research Institute of Petroleum Exploration and Development) | Jia, Ailin (Research Institute of Petroleum Exploration and Development) | Wei, Yunsheng (Research Institute of Petroleum Exploration and Development) | Qi, Yadong (Research Institute of Petroleum Exploration and Development)
Semi-analytical modeling is an efficient method to obtain the transient response of fracture network. Since the fracture width is very small compared to the length, most semi-analytical models regard the fracture panel as 1D linear flow with a continuous line source along which the exchange of influx rate is nonuniformly distributed. In contrast, the purpose of this paper is to explicitly represent realistic finite-volume fractures where the flow pattern is two-dimensional and captures the details of the flow exchange between the porous media and fracture. A methodology similar to the boundary element method (BEM) is developed to simulate the transient pressure behavior for discretely and contiously fractured media. Numerous case studies are presented to validate the approach in comparison to full numerical simulation and existing solutions published in the literature. Case studies also demonstrate its capability to simulate different types of fractured medium.