Modeling the Risk of Commercial Failure for Hydraulic Fracturing Projects Due to Reservoir Heterogeneity

Hydraulic fracturing technologies play a major role in the global energy supply and affect oil pricing. The current oil price fluctuations within 40 to 55 USD per barrel have caused diminished economical margins for hydraulic fracturing projects. Hence, successful decision making the for execution of hydraulic fracturing projects requires a higher level of integration of technical, commercial, and uncertainty analyses. However, the complexity of hydraulic fracturing modeling, and the sensitivity and the effects of uncertainty of reservoir heterogeneity on well performance renders the integration of such studies rather impractical. The impact of reservoir heterogeneity on hydraulic fracturing performance has been quantified by the introduction of Heterogeneity Impact Factor (HIF) and formulas have been developed to forecast well performance using HIF. These advances provide a platform for introducing a practical approach for introducing the Risk of Commercial Failure (RCF) due to reservoir heterogeneity in hydraulic fracturing projects. This paper defines such a parameter and the methodology to calculate it in a time-efficient manner. The proposed approach has been exercised on a real project in which a RCF of 20% is computed. The analysis also covers the sensitivity on Capital Expenditure (CAPEX), Operational Expenditure (OPEX), gas price, HIF and discount rate

Coupled Simulation Of Hydraulic Fracturing, Production, And Refracturing For Unconventional Reservoirs

Horizontal well drilling and multi-stage hydraulic fracturing are two key techniques for the development of unconventional reservoir. However, the production from tight formation is associate with fast depletion of reservoir. When oil price is low, drilling new horizontal wells is not profitable. Creating secondary fractures from existing hydraulic fractured wells, i.e., refracture is an alternative method to increase stimulated reservoir volume (SRV) and gain additional production from existing hydraulic fractured wells. To optimize refracturing well selection and operation, it’s of economic importance to acquire knowledge from initial hydraulic fracturing operation, production history, and refracturing design perspectives. This initiated the idea of this research to develop an integrated hydraulic fracturing, production, and refracturing model. This research work mainly comprises of three sections. In the first section, hydraulic fracturing models were built using XSite software, a lattice-based simulator, to analyze the effect of changing rock properties and in-situ stresses on fracture propagation in a layered reservoir. The challenge was to quantify degree of fracture containment using the hydraulic fracturing simulator. To overcome this fracture aperture contours were obtained to quantify fracture containment with two proposed penetration parameters. The modeling results suggest that brittle rocks favor vertical migration of hydraulic fracture, while increasing minimum horizontal stress tends to inhibit vertical growth of hydraulic fracture and lead to containment at layer interface. In the Second part of this study, an innovative integrated multi-stage hydraulic fracturing and production model was built for a shale gas reservoir. The challenge was to utilize distributed fracture data presented from the lattice-based hydraulic fracturing simulator for history matching in the reservoir simulator. To identify fracture geometry, a moving tip clustering and linear regression clustering algorithms were developed to discretize distributed fracture data points using multiple crack segments. The former algorithm is prone to capture fracture with microcracks that contribute to SRV, thus contributing to higher simulated production. The latter algorithm mainly captures the major fracture path without consideration of microcracks. The modeling results also suggest that gas slippage, matrix shrinkage, and fracture closure play important roles in shale gas production. In the third section, an innovative hydraulic fracturing, production, refracturing, and post-refracturing production model was developed. The challenge in this part was to simulate refracture propagation based on existing fracture geometry and pore pressure distribution with higher accuracy and efficiency. A model was built by simulating the fracture and refracture propagation in XSite and modeling reservoir depletion and post refracturing reservoir depletion in the continuum mechanism based simulator. The results suggest the propagation of refractures is driven by proppant and depletion induced stress shadow and contributes to larger SRV and higher hydrocarbon production. The proposed algorithms and integrated models can potentially be applied in the field for better refracturing design to enhance ultimate recovery of oil and gas

Recent comprehensive review for extended finite element method (XFEM) based on hydraulic fracturing models for unconventional hydrocarbon reservoirs

Hydraulic fracturing has been around for several decades since 1860s. It is one of the methods used to recover unconventional gas reservoirs. Hydraulic fracturing design is a challenging task due to the reservoir heterogeneity, complicated geological setting and in situ stress field. Hence, there are plenty of fracture modelling available to simulate the fracture initiation and propagation. The purpose of this paper is to provide a review on hydraulic fracturing modelling based on current hydraulic fracturing literature. Fundamental theory of hydraulic fracturing modelling is elaborated. Effort is made to cover the analytical and numerical modelling, while focusing on eXtended Finite Element Modelling (XFEM)

APPLYING HYDRAULIC FRACTURING IN EXTENDING PERFORATION LENGTH

"Applying Hydraulic Fracturing In Extending Perforation Length" is a final year project which consist of two parts, gather relevant literature data and simulate pressure transient. The main outcome is to evaluate the hydraulic fracturing treatment effectiveness in extending perforation penetration. The core of this project is simulation using pressure and production rate history in order to obtain reservoir data before and after hydraulic fracturing. The author has divided Final Year Project I (FYP I) into two phases namely, (1) Write literature review on the project, (2) Gather raw data on real case study continuously for the whole FYP 1. In Final Year Project 2 (FYP 2), it is the continuous from FYP 1 and focusing on full analysis of pressure and production rate data from real well. Kappa Saphir Well Test Software is the main tool for this project. Analysis can be performing after run the pressure and production data in the software. Firstly is analysis on the well test job sequence. During this part, the author will separate the fluctuation of plotted pressure data history accordingly to operation or job done following the time period. Thus, the author can know the response of the pressure towards the job done by engineer. Second, the author does the analysis on pressure transient. In this period, selected reservoir model and type curve will try to be match with the plotted pressure. As the model match, the well properties can be estimated. The analysis will be performing on pressure and production data before and after hydraulic fracturing treatment. For the last part, the author will evaluate the effectiveness of hydraulic fracturing. After gone through with this project, the author conclude that hydraulic fracturing can increase the production from a reservoir and perforation length as well as reservoir properties are changing after performed hydraulic fracturing

NUMERICAL MODELING OF HYDRAULIC FRACTURING IN SHALE OIL FORMATION

Shale oil reservoir is one of the modern studies that oil and gas industries have started to concern about it. Although its permeability is very low, shale oil reservoirs can be produced by using many techniques such as hydraulic fracturing method. Since the shale oil reservoir is much complicated, it is challenging to study hydraulic fracturing in this reservoir. Among the literature review, basic theories of hydraulic fracturing technique, how the process is performed, equipment used, and some fracture geometry models, will be discussed. There are several computer software programs that have been established to help petroleum engineers and planners to model hydraulic fracturing. These programs use numerical methods to model fracture propagation through the targeted formation. The user of this model will insert the necessary input parameters to that model. Eventually, the final output of these models will be the fracture geometry which is mainly the width and length of the fracture. The aim of this study is to analyze the two dimensional models which are Perkins-Kern-Nordgen, PKN and Geertsma de-Klerk, KGD fracture propagation models to obtain the geometry of the fracture based on the rock data as well as fracture treatment data. The realization of this project will intensify the knowledge and it will help in the future researches of hydraulic fracturing for shale oil reservoir

A Review of Fracturing Technologies Utilized in Shale Gas Resources

The modern hydraulic fracturing technique was implemented in the oil and gas industry in the 1940s. Since then, it has been used extensively as a method of stimulation in unconventional reservoirs in order to enhance hydrocarbon recovery. Advances in directional drilling technology in shale reservoirs allowed hydraulic fracturing to become an extensively common practice worldwide. Fracturing technology can be classified according to the type of the fracturing fluid with respect to the well orientation into vertical, inclined, or horizontal well fracturing. Depth, natural fractures, well completion technology, capacity, and formation sensitivity of a shale reservoir all play a role in the selection of fracturing fluid and fracturing orientation. At present, the most commonly used technologies are multi-section fracturing, hydra-jet fracturing, fracture network fracturing, re-fracturing, simultaneous fracturing, and CO2 and N2 fracturing. This chapter briefly reviews the technologies used in shale reservoir fracturing

In situ stresses and hydraulic fracturing in Hassi Messaoud Reservoir, Algeria

Thesis (M.S.)--University of Oklahoma, 1999.Includes bibliographical references (leaves 95-99).Understanding the rock mechanics aspects of Hassi Messaoud (HMD) reservoir is extremely important not only for hydraulic fracturing purposes but also for planning horizontal well drilling and completion. Analysis of the data generated from the hydraulic fracturing experience in Hassi Messaoud shows that fracturing is strongly lithology dependent. The magnitude and the orientation of the stress characterize the stress field. The stress magnitude in HMD is correlated to Young's modulus and shaliness. A new correlation is proposed relating minimum horizontal stress, shaliness and porosity. The stress field orientation in Hassi Messaoud fits that observed in other locations throughout Algeria. The maximum principal stress is in the azimuth direction between 135-140° azimuth, perpendicular to HMD anticline trend. The iso-fracturing gradient map of HMD structure confirms the compartmentalization of the reservoir into two compartments , the eastern and the western compartments, the former having, relatively, low fracturing gradients and the latter having higher fracturing gradients. The results of this study could be used in the selection of candidate wells for hydraulic fracturing as well as planning horizontal well drilling and completion

3-D Stress Redistribution During Hydraulic Fracturing Stimulation And Its Interaction With Natural Fractures In Shale Reservoirs

The hydraulic fracturing (also called fracturing, or fracking) technique has been widely applied in many fields, such as the enhanced geothermal systems (EGS), the improvement of injection rates for geologic sequestration of CO2, and for the stimulations of oil and gas reservoirs, especially for unconventional reservoirs with extremely low permeability. The key point for the success of hydraulic fracturing operations in unconventional resources is to connect and reactivate natural fractures and create the effective fracture network for fluid flow from pores into the production wells. To understand hydraulic fracturing technology, we must to understand some other affecting factors, e.g. in-situ stress conditions, reservoir mechanical properties, natural fracture distribution, and redistribution of the stress regime around the hydraulic fracture. Therefore, an accurate estimation of the redistribution of pore pressure and stresses around the hydraulic fracture is necessary, and it is very important to find out the reactivations of pre-existing natural fractures during the hydraulic fracturing process. Generally, fracture extension as well as its surround pore pressure and stress regime are affected by: poro- and thermoelastic phenomena as well as by fracture opening under the combined action of applied pressure and in-situ stresses. In this thesis, the previous studies on the hydraulic fracturing modeling and simulations were reviewed; a comprehensive semi-analytical model was constructed to estimate the pore pressure and stress distribution around an injection induced fracture from a single well in an infinite reservoir. With Mohr-Coulomb failure criterion, the natural fracture reactivation potential around the hydraulic fracture were studied. Then, a few case studies were presented, especially with the application in unconventional natural fractured shale reservoirs. This work is of interest in interpretation of micro-seismicity in hydraulic fracturing and in assessing permeability variation around a stimulation zone, as well as in estimation of the fracture spacing during hydraulic fracturing operations. In addition, the results from this study can be very helpful for selection of stimulated wells and further design of the re-fracturing operations

Application of the Variational Fracture Model to Hydraulic Fracturing in Poroelastic Media

Hydraulic fracturing has persisted through the use of simple numerical models to describe fracture geometry and propagation. Field tests provide evidence of interaction and merging of multiple fractures, complex fracture geometry and propagation paths. These complicated behaviors suggest that the simple models are incapable of serving as predictive tools for treatment designs. In addition, other commonly used models are designed without considering poroelastic effects even though a propagating hydraulic fracture induces deformation of the surrounding porous media. A rigorous hydraulic fracturing model capable of reproducing realistic fracture behaviors should couple rock deformation, fracture propagation and fluid flow in the both the fracture and reservoir. In this dissertation, a fully coupled hydraulic fracturing simulator is developed by coupling reservoir-fracture flow models with a mechanical model for reservoir deformation. Reservoir-fracture deformation is modeled using the variational fracture model which provides a unified framework for simultaneous description of fracture deformation and propagation, and reservoir deformation. Its numerical implementation is based on a phase-field regularized model. This approach avoids the need for explicit knowledge of fracture location and permits the use of a single computational domain for fracture and reservoir representation. The first part of this work involves verification of the variational fracture model by solving the classical problem of fracture propagation in impermeable reservoirs due to injection of an inviscid fluid. Thereafter, the developed reservoir-fracture model is coupled to the mechanical model. Iterative solution of the variational fracture model and the coupled flow model provides a simplified framework for simultaneous modeling of rock deformation and fluid flow during hydraulic fracturing. Since the phase field technique for fracture representation removes the limitation of knowing a priori, fracture direction, the numerical solutions provide a means of evaluating the role of reservoir and fluid properties on fracture geometry and propagation paths. First, the proposed approach is validated for simple idealized scenarios for which closed form solutions exist in the literature. Further simulations highlight the role of fluid viscosity and reservoir properties on fracture length, fracture width and fluid pressure. Numerical results show stress shadowing effect on multiple hydraulic fracture propagation. Finally, the effect of in situ stress on fracture propagation direction is reproduced while the role of varying reservoir mechanical properties on fracture height growth is investigated