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Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (1 September 2019) | Viewed by 40627

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Special Issue Editors

Prof. Dr. Ruud Weijermars

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Petroleum Engineering Department, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia
Interests: flow in fractured porous media; hydraulic fracture propagation; wellbore stability under anisotropy; reservoir models; production forecasting
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Dr. Wei Yu

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Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, TX 77843-3116, USA
Interests: embedded discrete fracture model; fractured reservoir simulation; automatic history matching; data mining

Dr. Aadi Khanal

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Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, TX 77843-3116, USA
Interests: production forecasting of unconventional reservoirs; reservoir simulation and uncertainty analysis; fracture and well spacing optimization

Special Issue Information

Dear Colleagues,

The massive increase in energy demand and related rapid development of unconventional reservoirs has opened up exciting new energy supply opportunities along with new, seemingly intractable, engineering and research challenges. The energy industry has primarily depended on a heuristic approach, rather than a systematic approach, to optimize and tackle the various challenges when developing new and improving the performance of existing unconventional reservoirs. This special issue solicits original and high-quality research articles related to the modeling of unconventional reservoirs. We seek to showcase advanced methods for fractured reservoir simulation, and improved production forecasting techniques. Industry needs accurate estimations of well production performance and of the cumulative, estimated ultimate reserves, accounting for uncertainty.

Of particular interest are original papers on:

Advanced reservoir models for multistage fractured wells
Reservoir flow models linked to fracture treatment models
Models for matrix permeability enhancement
Reservoir models accounting for non-planar hydraulic fractures
Interaction with natural fracture systems
Pore-scale phenomena affecting well productivity in unconventional reservoirs
Models of multi-phase flow to optimize production from unconventional reservoirs
Novel production forecasting techniques for better reserves estimation
Uncertainty quantification and history matching using real field data
Field studies of well performance and probabilistic reserves estimation
Field development strategies based on reservoir response models

Prof. Dr. Ruud Weijermars
Dr. Wei Yu
Dr. Aadi Khanal
Guest Editors

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Keywords

reservoir simulation
production forecasting
history matching
fracture hits
parent child well interaction
impact of natural fractures
nanopore transport mechanisms
multiphase flow
uncertainty quantification

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Published Papers (10 papers)

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Research

36 pages, 12285 KiB

Open AccessArticle

Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

by Kiran Nandlal and Ruud Weijermars

Energies 2019, 12(20), 3852; https://doi.org/10.3390/en12203852 - 11 Oct 2019

Cited by 11 | Viewed by 3083

Abstract

Hydraulic fracturing for economic production from unconventional reservoirs is subject to many subsurface uncertainties. One such uncertainty is the impact of natural fractures in the vicinity of hydraulic fractures in the reservoir on flow and thus the actual drained rock volume (DRV). We delineate three fundamental processes by which natural fractures can impact flow. Two of these mechanisms are due to the possibility of natural fracture networks to possess (i) enhanced permeability and (ii) enhanced storativity. A systematic approach was used to model the effects of these two mechanisms on flow patterns and drained regions in the reservoir. A third mechanism by which natural fractures may impact reservoir flow is by the reactivation of natural fractures that become extensions of the hydraulic fracture network. The DRV for all three mechanisms can be modeled in flow simulations based on Complex Analysis Methods (CAM), which offer infinite resolution down to a micro-fracture scale, and is thus complementary to numerical simulation methods. In addition to synthetic models, reservoir and natural fracture data from the Hydraulic Fracturing Test Site (Wolfcamp Formation, Midland Basin) were used to determine the real-world impact of natural fractures on drainage patterns in the reservoir. The spatial location and variability in the DRV was more influenced by the natural fracture enhanced permeability than enhanced storativity (related to enhanced porosity). A Carman–Kozeny correlation was used to relate porosity and permeability in the natural fractures. Our study introduces a groundbreaking upscaling procedure for flows with a high number of natural fractures, by combining object-based and flow-based upscaling methods. A key insight is that channeling of flow through natural fractures left undrained areas in the matrix between the fractures. The flow models presented in this study can be implemented to make quick and informed decisions regarding where any undrained volume occurs, which can then be targeted for refracturing. With the method outlined in our study, one can determine the impact and influence of natural fracture sets on the actual drained volume and where the drainage is focused. The DRV analysis of naturally fractured reservoirs will help to better determine the optimum hydraulic fracture design and well spacing to achieve the most efficient recovery rates. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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24 pages, 3841 KiB

Open AccessEditor’s ChoiceArticle

Generalized Extreme Value Statistics, Physical Scaling and Forecasts of Oil Production in the Bakken Shale

by Wardana Saputra, Wissem Kirati and Tadeusz Patzek

Energies 2019, 12(19), 3641; https://doi.org/10.3390/en12193641 - 24 Sep 2019

Cited by 17 | Viewed by 5531

Abstract

We aim to replace the current industry-standard empirical forecasts of oil production from hydrofractured horizontal wells in shales with a statistically and physically robust, accurate and precise method of matching historic well performance and predicting well production for up to two more decades. Our Bakken oil forecasting method extends the previous work on predicting fieldwide gas production in the Barnett shale and merges it with our new scaling of oil production in the Bakken. We first divide the existing 14,678 horizontal oil wells in the Bakken into 12 static samples in which reservoir quality and completion technologies are similar. For each sample, we use a purely data-driven non-parametric approach to arrive at an appropriate generalized extreme value (GEV) distribution of oil production from that sample’s dynamic well cohorts with at least

1, 2, 3, \dots

years on production. From these well cohorts, we stitch together the

P_{50}

P_{10}

, and

P_{90}

statistical well prototypes for each sample. These statistical well prototypes are conditioned by well attrition, hydrofracture deterioration, pressure interference, well interference, progress in technology, and so forth. So far, there has been no physical scaling. Now we fit the parameters of our physical scaling model to the statistical well prototypes, and obtain a smooth extrapolation of oil production that is mechanistic, and not just a decline curve. At late times, we add radial inflow from the outside. By calculating the number of potential wells per square mile of each Bakken region (core and noncore), and scheduling future drilling programs, we stack up the extended well prototypes to obtain the plausible forecasts of oil production in the Bakken. We predict that Bakken will ultimately produce 5 billion barrels of oil from the existing wells, with the possible addition of 2 and 6 billion barrels from core and noncore areas, respectively. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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20 pages, 7076 KiB

Open AccessArticle

An Efficient Hybrid Model for Nonlinear Two-Phase Flow in Fractured Low-Permeability Reservoir

by Daigang Wang, Jingjing Sun, Yong Li and Hui Peng

Energies 2019, 12(15), 2850; https://doi.org/10.3390/en12152850 - 24 Jul 2019

Cited by 11 | Viewed by 3055

Abstract

The staged fracturing horizontal well has proven to be an attractive alternative for improving the development effect of a low permeability waterflood reservoir. Due to the coexistence of matrix, fracture, and horizontal wellbore, it remains a great challenge to accurately simulate the nonlinear flow behaviors in fractured porous media. Using a discrete fracture model to reduce the dimension of the fracture network, a two-parameter model is used to describe the nonlinear two-phase flow behavior, and the equivalent pipe flow equation is selected to estimate the horizontal wellbore pressure drop in the fractured low-permeability reservoir. A hybrid mathematical model for the nonlinear two-phase flow, including the effect of horizontal wellbore pressure drop in fractured porous media, is developed. A numerical scheme of the hybrid model is derived using the mimetic finite difference method and finite volume method. With a staggered five-spot flood system, the accuracy of the proposed model and the effect of fracture properties on nonlinear two-phase flow behaviors are further investigated. The results also show that with an increase of fracture length near injectors, the breakthrough time of injected water into the horizontal wellbore will be shorter, indicating a faster rise of the water cut, and a worse development effect. The impact of shortening fracture spacing is consistent with that of enlarging fracture length. Successful practice in modeling the complex waterflood behaviors for a 3-D heterogeneous reservoir provides powerful evidence for the practicability and reliability of our model. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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20 pages, 12158 KiB

Open AccessArticle

History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

by Juhyun Kim, Youngjin Seo, Jihoon Wang and Youngsoo Lee

Energies 2019, 12(9), 1634; https://doi.org/10.3390/en12091634 - 29 Apr 2019

Cited by 6 | Viewed by 4315

Abstract

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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28 pages, 8045 KiB

Open AccessArticle

Analysis of Pressure Communication between the Austin Chalk and Eagle Ford Reservoirs during a Zipper Fracturing Operation

by Sriniketh Sukumar, Ruud Weijermars, Ibere Alves and Sam Noynaert

Energies 2019, 12(8), 1469; https://doi.org/10.3390/en12081469 - 18 Apr 2019

Cited by 11 | Viewed by 4998

Abstract

The recent interest in redeveloping the depleted Austin Chalk legacy field in Bryan (TX, USA) mandates that reservoir damage and subsurface trespassing between adjacent reservoirs be mitigated during hydraulic fracture treatments. Limiting unintended pressure communication across reservoir boundaries during hydraulic fracturing is important for operational efficiency. Our study presents field data collected in fall 2017 that measured the annular pressure changes that occurred in Austin Chalk wells during the zipper fracturing treatment of two new wells in the underlying Eagle Ford Formation. The data thereby obtained, along with associated Eagle Ford stimulation reports, was analyzed to establish the degree of pressure communication between the two reservoirs. A conceptual model for pressure communication is developed based on the pressure response pattern, duration, and intensity. Additionally, pressure depletion in the Austin Chalk reservoir is modeled based on historic production data. Pressure increases observed in the Austin Chalk wells were about 6% of the Eagle Ford injection pressures. The pressure communication during the fracture treatment was followed by a rapid decline of the pressure elevation in the Austin Chalk wells to pre-fracture reservoir pressure, once the Eagle Ford fracture operation ended. Significant production uplifts occurred in several offset Austin Chalk wells, coeval with the observed temporal pressure increase. Our study confirms that after the rapid pressure decline following the short-term pressure increase in the Austin Chalk, no residual pressure communication remained between the Austin Chalk and Eagle Ford reservoirs. Limiting pressure communication between adjacent reservoirs during hydraulic fracturing is important in order to minimize the loss of costly fracturing fluid and to avoid undue damage to the reservoir and nearby wells via unintended proppant pollution. We provide field data and a model that quantifies the degree of pressure communication between adjacent reservoirs (Austin Chalk and Eagle Ford) for the first time. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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13 pages, 2566 KiB

Open AccessArticle

Numerical Study of Simultaneous Multiple Fracture Propagation in Changning Shale Gas Field

by Jun Xie, Haoyong Huang, Yu Sang, Yu Fan, Juan Chen, Kan Wu and Wei Yu

Energies 2019, 12(7), 1335; https://doi.org/10.3390/en12071335 - 8 Apr 2019

Cited by 10 | Viewed by 2831

Abstract

Recently, the Changning shale gas field has been one of the most outstanding shale plays in China for unconventional gas exploitation. Based on the more practical experience of hydraulic fracturing, the economic gas production from this field can be optimized and gradually improved. However, further optimization of the fracture design requires a deeper understanding of the effects of engineering parameters on simultaneous multiple fracture propagation. It can increase the effective fracture number and the well performance. In this paper, based on the Changning field data, a complex fracture propagation model was established. A series of case studies were investigated to analyze the effects of engineering parameters on simultaneous multiple fracture propagation. The fracture spacing, perforating number, injection rate, fluid viscosity and number of fractures within one stage were considered. The simulation results show that smaller fracture spacing implies stronger stress shadow effects, which significantly reduces the perforating efficiency. The perforating number is a critical parameter that has a big impact on the cluster efficiency. In addition, one cluster with a smaller perforating number can more easily generate a uniform fracture geometry. A higher injection rate is better for promoting uniform fluid volume distribution, with each cluster growing more evenly. An increasing fluid viscosity increases the variation of fluid distribution between perforation clusters, resulting in the increasing gap between the interior fracture and outer fractures. An increasing number of fractures within the stage increases the stress shadow among fractures, resulting in a larger total fracture length and a smaller average fracture width. This work provides key guidelines for improving the effectiveness of hydraulic fracture treatments. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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39 pages, 13534 KiB

Open AccessFeature PaperArticle

Elementary Pore Network Models Based on Complex Analysis Methods (CAM): Fundamental Insights for Shale Field Development

by Ruud Weijermars and Aadi Khanal

Energies 2019, 12(7), 1243; https://doi.org/10.3390/en12071243 - 1 Apr 2019

Cited by 5 | Viewed by 3422

Abstract

This paper presents insights on flow in porous media from a model tool based on complex analysis methods (CAM) that is grid-less and therefore can visualize fluid flow through pores at high resolution. Elementary pore network models were constructed to visualize flow and the corresponding dynamic bottomhole pressure (BHP) profiles in a well at reservoir outflow points. The pore networks provide the flow paths in shale for transferring hydrocarbons to the wellbore. For the base case model, we constructed a single flow path made up of an array of pores and throats of variable diameter. A passive ganglion (tracer) of an incompressible fluid was introduced to demonstrate the deformation of such ganglions when moving through the pores. The simplified micro-flow channel model was then expanded by stacking flow elements vertically and horizontally to create complex flow paths representing a small section of a porous reservoir. With these model elements in place, the flow transition from the porous reservoir fluid to the wellbore was modeled for typical stages in a well life. The dynamic component of the bottomhole pressure (BHP) was modeled not only during production but also during the drilling of a formation (with either balanced, underbalanced or overbalanced wellbore pressure). In a final set of simulations, the movement of an active ganglion (with surface tension) through the pore space was simulated by introducing a dipole element (which resisted deformation during the movement through the pores). Such movement is of special interest in shale, because of the possible delay in the onset of bubble point pressure due to capillarity. Capillary forces may delay the reservoir to reach the bubble point pressure, which postpones the pressure-drop trigger that would lead to an increase of the gas–oil ratio. The calculation of the estimated ultimate recovery (EUR) with an erroneous assumption of an early increase in the gas–oil ratio will result in a lower volume than when the bubble point delay is considered. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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16 pages, 9214 KiB

Open AccessArticle

Investigation of the Effect of Natural Fractures on Multiple Shale-Gas Well Performance Using Non-Intrusive EDFM Technology

by Wei Yu, Xiaohu Hu, Malin Liu and Weihong Wang

Energies 2019, 12(5), 932; https://doi.org/10.3390/en12050932 - 10 Mar 2019

Cited by 11 | Viewed by 4211

Abstract

The influence of complex natural fractures on multiple shale-gas well performance with varying well spacing is poorly understood. It is difficult to apply the traditional local grid refinement with structured or unstructured gridding techniques to accurately and efficiently handle complex natural fractures. In this study, we introduced a powerful non-intrusive embedded discrete fracture model (EDFM) technology to overcome the limitations of exiting methods. Through this unique technology, complex fracture configurations can be easily and explicitly embedded into structured matrix blocks. We set up a field-scale two-phase reservoir model to history match field production data and predict long-term recovery from Marcellus. The effective fracture properties were determined thorough history matching. In addition, we extended the single-well model to include two horizontal wells with and without including natural fractures. The effects of different numbers of natural fractures on two-well performance with varying well spacing of 200 m, 300 m, and 400 m were examined. The simulation results illustrate that gas productivity almost linearly increases with the number of two-set natural fractures. Furthermore, the difference of well performance between different well spacing increases with an increase in natural fracture density. A larger well spacing is preferred for economically developing the shale-gas reservoirs with a larger natural fracture density. The findings of this study provide key insights into understanding the effect of natural fractures on well performance and well spacing optimization. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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15 pages, 2924 KiB

Open AccessArticle

Fracture Detection and Numerical Modeling for Fractured Reservoirs

by Lihua Zuo, Xiaosi Tan, Wei Yu and Xiaodong Hu

Energies 2019, 12(3), 386; https://doi.org/10.3390/en12030386 - 26 Jan 2019

Cited by 6 | Viewed by 3799

Abstract

The subsurface fractures could impact the fluid mechanisms dramatically, which makes the modeling of the hydraulic and natural fractures an essential step for fractured reservoirs simulations. However, because of the complexities of fracture patterns and distributions, it is difficult to detect and quantify the fracture networks. In this study, line detection techniques are designed and applied to quantify the fracture segments from fracture figures. Using this fracture detection algorithm, the fracture segments could be located by detecting the endpoints and the intersections of fractures, thus that the fracture patterns could be accurately captured and characterized. The proposed method is applied to two previous well-known field cases and the pressure distribution results are consistent with the micro-seismic data profiles. These two field cases are simulated and computed by using a semianalytical model and Embedded Discrete Fracture Model (EDFM) respectively. The third case is constructed by the fracture outcrop figure and simulated by a numerical simulator with EDFM implemented. The simulation results are accurate and clearly illustrate the important role fractures play in unconventional reservoirs. The technology proposed in this study could be used to quantify the fracture input data for reservoir simulations and be easily expanded for fracture detection and characterization problems in other fields. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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15 pages, 4317 KiB

Open AccessFeature PaperArticle

Cyclic CH₄ Injection for Enhanced Oil Recovery in the Eagle Ford Shale Reservoirs

by Yuan Zhang, Yuan Di, Yang Shi and Jinghong Hu

Energies 2018, 11(11), 3094; https://doi.org/10.3390/en11113094 - 9 Nov 2018

Cited by 17 | Viewed by 4274

Abstract

Gas injection is one of the most effective enhanced oil recovery methods for the unconventional reservoirs. Recently, CH₄ has been widely used; however, few studies exist to accurately evaluate the cyclic CH₄ injection considering molecular diffusion and nanopore effects. Additionally, the effects of operation parameters are still not systematically understood. Therefore, the objective of this work is to build an efficient numerical model to investigate the impacts of molecular diffusion, capillary pressure, and operation parameters. The confined phase behavior was incorporated in the model considering the critical property shifts and capillary pressure. Subsequently, we built a field-scale simulation model of the Eagle Ford shale reservoir. The fluid properties under different pore sizes were evaluated. Finally, a series of studies were conducted to examine the contributions of each key parameter on the well production. Results of sensitivity analysis indicate that the effect of confinement and molecular diffusion significantly influence CH₄ injection effectiveness, followed by matrix permeability, injection rate, injection time, and number of cycles. Primary depletion period and soaking time are less noticeable for the well performance in the selected case. Considering the effect of confinement and molecular diffusion leads to the increase in the well performance during the CH₄ injection process. This work, for the first time, evaluates the nanopore effects and molecular diffusion on the CH₄ injection. It provides an efficient numerical method to predict the well production in the EOR process. Additionally, it presents useful insights into the prediction of cyclic CH₄ injection effectiveness and helps operators to optimize the EOR process in the shale reservoirs. Full article

(This article belongs to the Special Issue Improved Reservoir Models and Production Forecasting Techniques for Multi-Stage Fractured Hydrocarbon Wells)

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