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In addition to knowing the values of in-situ stress, it is also extremely important to know the values of formation permeability in every rock layer. It is impossible to optimize the location of the perforations, the length of the hydraulic fracture, the conductivity of the hydraulic fracture, and the well spacing, if one does not know the values of formation permeability in every rock layer. In addition, one must know the formation permeability to forecast gas reserves and to analyze post-fracture pressure buildup tests. To determine the values of formation permeability, one can use data from logs, cores, production tests, and prefracture pressure buildup tests or injection falloff tests. The most data that are available vs. depth comes from openhole logs.
There are many factors that the engineer must consider when analyzing the behavior of a well after it has been fracture treated. The engineer should analyze the productivity index of the well both before and after the fracture treatment. Other factors of importance are ultimate oil and gas recovery and calculations to determine the propped fracture length, the fracture conductivity, and the drainage area of the well. Post-fracture treatment analyses of the fracture treatment data, the production data, and the pressure data can be very complicated and time consuming. However, without adequate post-fracture evaluation, it will be impossible to continue the fracture treatment optimization process on subsequent wells. Many of the early treatments in the 1950s were designed to increase the productivity index of damaged wells.
Many wells, particularly gas wells in low-permeability formations require hydraulic fracturing to be commercially viable. Interpretation of pressure-transient data in hydraulically fractured wells is important for evaluating the success of fracture treatments and predicting the future performance of fractured wells. This page includes graphical techniques for analyzing post-fracture pressure transient tests after identifying several flow patterns that are characteristic of hydraulically fractured wells. Often, identification of specific flow patterns can aid in well test analysis. Five distinct flow patterns (Figure 1) occur in the fracture and formation around a hydraulically fractured well.
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.
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.
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.
Pseudo-steady state (or pseudo steady-state), is also referred to as "stabilized," or as "steady state in a bounded drainage area." This type of reservoir flow occurs much more frequently than steady-state flow or unsteady-state flow with an expanding drainage radius. Pseudo-steady state (PSS) flow occurs during the late time region when the outer boundaries of the reservoir are all no flow boundaries. This includes not only the case when the reservoir boundaries are sealing faults, but also when nearby producing wells cause no flow boundaries to arise. During the PSS flow regime, the reservoir behaves as a tank.
Summary Reduction of fracture/well spacing and increases in hydraulic fracture stimulation treatment size are popular strategies for improving hydrocarbon recovery from multifractured horizontal wells (MFHWs). However, these strategies can also increase the chance of fracture interference, which can not only negatively impact the overall production but also introduce complexities for production data analysis. A semianalytical model is therefore developed to analyze production data from two communicating MFHWs and applied to a field case. The new semianalytical model uses the dynamic drainage area (DDA) concept and assumes three porosity regions. The three-region model is comprised of a primary hydraulic fracture (PHF), an enhanced fractured region (EFR) adjacent to the PHF, and a nonstimulated region (NSR). Assuming a well pair primarily communicates through PHFs, the equations for two communicating wells are coupled and solved simultaneously to model the fluid transfer between the wells. This method is used within a history-matching framework to estimate the communication between the wells by matching the production data. The semianalytical model is first verified against a more rigorous, fully numerical simulation model for a range of fracture/reservoir properties. These comparisons demonstrate that there is excellent agreement between the fully numerical simulation model results and the new semianalytical model. The semianalytical model is then employed to history-match production data from six MFHWs (drilled from two adjacent well pads) exhibiting different degrees of communication. For the purpose of history matching the data, only strong communication between pairs of wells (intrapair communication) is considered in the three-region model, and the results show good agreement with the field data. A flexible, yet simple, semianalytical model is developed for the first time that can accurately model the communication between multiple well pairs. This approach can be used by reservoir engineers to analyze the production data from communicating MFHWs.
Summary We propose a novel method for estimating average fracture compressibility during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our estimates (4 to 22×10psi) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.
This paper presents methods for production forecasting that give reasonable post-treatment predictions that have been found to be useful for economic planning. The proposed methodology provides an economically viable plan for optimizing lateral length, fracture spacing, and treatment design. The methodology focuses on the post-simulation effective reservoir volume. Results show that increasing apparent fracture length rarely affects long-term recovery. Likewise, adding more fractures within the same reservoir volume may increase early-time production rate and decline rate without contacting more reservoir volume or adding to long-term recovery.