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Smith and Hannah documented the evolution of hydraulic fracturing in high-permeability reservoirs since the 1950s. The first fracture treatments in the 1950s were pumped in moderate- to high-permeability formations. Those treatments were designed to remove formation damage that usually occurred during the drilling and completion operations. Low-permeability reservoirs were fracture treated in the 1950s and 1960s, but, at low oil and gas prices, low-permeability reservoirs were generally not economic, even after a successful fracture treatment. The values of high, moderate, and low permeability need to be defined on the basis of both the formation permeability and the reservoir fluid viscosity, or the k/μ ratio, where k is the formation permeability in md, and μ is the formation fluid viscosity in cp.
Introduction The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping a fluid into a wellbore at an injection rate that is too great for the formation to accept in a radial flow pattern. As the resistance to flow in the formation increases, the pressure in the wellbore increases to a value that exceeds the breakdown pressure of the formation open to the wellbore. Once the formation "breaks down," a fracture is formed, and the injected fluid begins moving down the fracture. In most formations, a single, vertical fracture is created that propagates in two directions from the wellbore. These fracture "wings" are 180 apart and normally are assumed to be identical in shape and size at any point in time; however, in actual cases, the fracture wing dimensions may not be identical. In naturally fractured or cleated formations, it is possible that multiple fractures can be created and propagated during a hydraulic fracture treatment. Fluid that does not contain any propping agent (called the "pad") is injected to create a fracture that grows up, out, and down, and creates a fracture that is wide enough to accept a propping agent. The purpose of the propping agent is to prop open the fracture once the pumping operation ceases, the pressure in the fracture decreases, and the fracture closes.
Dontsov, Egor (ResFrac Corporation) | Suarez-Rivera, Roberto (W. D. Von Gonten Laboratories) | Panse, Rohit (W. D. Von Gonten Laboratories) | Quinn, Christopher (W. D. Von Gonten Laboratories) | LaReau, Heather (BP America Production Company, BPx Energy Inc.) | Suter, Kirke (BP America Production Company, BPx Energy Inc.) | Hines, Chris (BP America Production Company, BPx Energy Inc.) | Montgomery, Ryan (BP America Production Company, BPx Energy Inc.) | Koontz, Kyle (BP America Production Company, BPx Energy Inc.)
Abstract As the number of wells drilled in regions with existing producing wells increases, understanding the detrimental impact of these by the depleted zone around parent wells becomes more urgent and important. This understanding should include being able to predict the extent and heterogeneity of the depleted region near the pre-existing wells, the resulting altered stress field, and the effect of this on newly created fractures from adjacent child wells. In this paper we present a workflow that addresses the above concern in the Eagle Ford shale play, using numerical simulations of fracturing and reservoir flow, to define the effect of the depletion zone on child wells and match their field production data. We utilize an ultra-fast hydraulic fracture and depletion model to conduct several hundred numerical simulations, with varying values of permeability and surface area, seeking for cases that match the field production data. Multiple solutions exist that match the field data equally well, and we used additional field production data of parent-child well-interaction, to select the most plausible model. Results show that the depletion zone is strongly non-uniform and that large reservoir regions remain undepleted. We observe two important effects of the depleted zone on fractures from child wells drilled adjacent to the parents. Some fractures propagate towards low pressure zones and do not contribute to production. Others are repelled by the higher stress region that develops around the depletion zone, propagate into undepleted rock, and have production rates commensurate to that from other child wells drilled away from depleted region. The observations are validated by the field data. Results are being used to optimize well placement and well spacing for subsequent field operations, with the objective to increase the effectiveness of the child wells.
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.
Abstract Most waterfloods in California target sandstone formations that are unconsolidated in nature with high porosities and high permeabilities. These formations are also characterized by high Poisson ratios and low values of Young's Moduli. There has been a concern if, during the waterfloods of these types of formations, fracturing takes place at high-injection gradients. The influence of various factors on leak-off is studied in detail, indicating that with an increase in rock permeability, the leak-off velocity increases. This study included a comprehensive analysis of the characteristics of such soft formations and their responses to high injection gradients. We show that if the leak-off factors are adjusted to reflect high permeability and proper geomechanical properties, the probability of fracture formation is nil at injection gradients up to 0.9 psi/ft, for unconsolidated rooks. We computed estimated fracture width, fracture height, fracture length and noted for all three calculations, it takes gradients approaching 1psi/ft to note a non-trivial estimated value for these characteristics. This study shows that for unconsolidated formations like those in California targeted for waterfloods, the probability of fracture formation under pressure gradients of 0.9 psi/ft. is nil, and high injectivities can be exercised without the fear of fracture formation.
Abstract Determining the closure pressure is crucial for optimal hydraulic fracturing design and successful execution of fracturing treatment. Historically, the use of diagnostic tests before the main fracturing treatment has significantly advanced to gain more information about the pattern of fracture propagation and fluid performance to optimize the designs. The goal is to inject a small volume of fracturing fluid to breakdown the formation and create small fracture geometry, then once pumping is stopped the pressure decline is analyzed to observe the fracture closure. Many analytical methods such as G-Function, square root of time, etc. have been developed to determine the fracture closure pressure. There are cases in which there is difficulty in determining the fracture closure pressure, as well as personal bias and field experiences make it challenging to interpret the changes in the pressure derivative slope and identify fracture closure. These conditions include: High permeability reservoirs where fracture closure occurs very fast due to the quick fluid leakoff. Extremely low permeability reservoir, which requires a long shut-in time for the fluid to leak off and determine the fracture closure pressure. The non-ideal fluid leak-off behavior under complex conditions. The objective of this study is to apply machine learning methods to implement a predesigned algorithm to execute the required tasks and predict the fracture closure pressure while minimizing the shortcomings in determining the closure pressure for non-ideal or subjective conditions. This paper demonstrates training different supervised machine learning algorithms to help predict fracture closure pressure. The workflow involves using the datasets to train and optimize the models, which subsequently are used to predict the closure pressure of testing data. The output results are then compared with actual results from more than 120 DFIT data points. We further propose an integrated approach to feature selection and dataset processing and study the effects of data processing on the success of the model prediction. The results from this study limit the subjectivity and the need for the experience of personal interpreting the data. We speculate that a linear regression and MLP neural network algorithms can yield high scores in the prediction of fracture closure pressure.
Summary The popular cohesive zone model (CZM) that only features decreasing cohesive traction along with crack separation might not adequately represent the fracturing behavior in organic-rich shale because of increased ductility. This paper proposes a novel CZM that can realize various traction/separation laws (TSLs) by a unified formulation to better represent the increased ductility of organic-rich shale. The implications of increased ductility in different forms on hydraulic fracturing were studied using the newly designed progressive parametric study. First, the shape of the TSL affects the hydraulic fracturing given the same cohesive crack energy and tensile strength, which further indicates the necessity of the newly proposed TSL. Second, the initial tensile strength, controlling when the cohesive crack starts propagating, has the greatest effect on the hydraulic fracturing among all TSL shape parameters. The effects of TSL parameters become less significant as the fracturing-fluid viscosity increases. Finally, Young's modulus among four common poroelastic parameters most significantly affects the brittleness of rock formation and hydraulic-fracture lengths. The increase in cohesive energy accompanied by the decrease of Young's modulus can greatly reduce the hydraulic-fracture length under the same injection volume. Introduction Shale as a common sedimentary rock is attracting more attention since the boom of exploration and production in unconventional oil and gas reservoirs with hydraulic fracturing. However, success of hydraulic fracturing in the important organic-rich shale is limited. The improvement of hydraulic-fracturing practices in these organic-rich shales awaits a better understanding of the effects of the increased ductility caused by ample organic matter. The core objective of this paper is to study the increased ductility of organic-rich shale and its effects on hydraulic fracturing by implementing a modified cohesive crack model into an appropriate numerical framework to handle fracture propagation. An in-house XFEM framework was developed to address the stronger ductility of organic-rich shale by use of the CZM.
Summary The primary objective of this study is to develop fast analytical and/or semianalytical (A/SA) solutions for the problem of liquid flow/production and pressure interference in multifractured systems between parallel horizontal wells in ultralow-permeability reservoirs. We propose a new A/SA method that reduces the 3D flow equation into either a simple algebraic equation or an ordinary differential equation (ODE) in a multitransformed space, the inversion of which yields solutions at any point in space and time. In the proposed transformational decomposition method (TDM), a general, fully linearized form of the 3D partial-differential equation (PDE) describing low-compressibility liquid flow through porous and fractured media is subjected first to Laplace transforms (LTs) to eliminate time, and then to successive finite cosine transforms (FCTs) that eliminate either all three dimensions, yielding a simple algebraic equation, or two dimensions, yielding an ODE in space only. Inversion of the solutions of the multitransformed space equations provides solutions that are analytical in space and semianalytical in time. The TDM completely eliminates the need for time and space discretization, thus dramatically reducing the input-data requirements and long execution times of numerical simulations. The Fortran 95 code for the TDM solutions requires limited inputs and is easy to use. Because of the linearity requirements of the Laplace transformation of the underlying PDE, the TDM is only rigorously applicable at greater than the bubblepoint pressure. Using 3D stencils (the minimum repeatable elements in the horizontal well and hydraulically fractured system) as the basis of our study, solutions over extended production times were obtained for a range of isotropic and anisotropic matrix and fracture properties, constant and time-variable production regimes (rates or bottomhole pressures), combinations of stimulated reservoir volume (SRV) and non-SRV subdomains, variable hydraulic-fracture (HF) dimensions, and inner and boundary (toe and heel) stencils. The results were compared with analytical solutions (available for simple problems and domain geometries), as well as with numerical solutions from a widely used, fully implicit 3D simulator that involves very fine discretization of a 3D domain comprising more than 356,000 elements. The TDM solutions were shown to be in excellent agreement with the reference analytical and/or numerical solutions, while requiring a fraction of the memory and execution times of the latter because of the elimination of the need for time and space discretization. The TDM is an entirely new approach for the analysis of low-compressibility liquid flow and pressure interference in hydraulically fractured ultralow-permeability reservoirs. The TDM solutions have the potential to provide a reliable and fast tool to identify the dominant mechanisms and factors controlling the system behavior and can act as the basis for a rapid initial parameter identification in a history-matching process for possible further refinement using full numerical modeling at less than the bubblepoint pressure.
Erofeev, A. S. (Skolkovo Institute of Science and Technology/Digital Petroleum (Corresponding author) | Orlov, D. M. (email: firstname.lastname@example.org)) | Perets, D. S. (Skolkovo Institute of Science and Technology/Digital Petroleum) | Koroteev, D. A. (Gazprom Neft, Science and Technology Center)
Summary We studied the applicability of a gradient-boostingmachine-learning (ML) algorithm for forecasting of oil and total liquid production after hydraulic fracturing (HF). A thorough raw data study with data preprocessing algorithms was provided. The data set included 10 oil fields with more than 2,000 HF events. Each event has been characterized by well coordinates, geology, transport and storage properties, depths, and oil/liquid rates before fracturing for target and neighboring wells. Each ML model has been trained to predict monthly production rates right after fracturing and when the flows are stabilized. The gradient-boosting method justified its choice with R being approximately 0.7 to 0.8 on the test set for oil/total liquid production after HF. The developed ML prediction model does not require preliminary numerical simulations of a future HF design. The applied algorithm could be used as a new approach for HF candidate selection based on the real-time state of the field.