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Liang, Feng (Aramco Services Company: Aramco Research Center—Houston) | Han, Yanhui (Aramco Services Company: Aramco Research Center—Houston) | Liu, Hui-Hai (Aramco Services Company: Aramco Research Center—Houston) | Saini, Rajesh (Aramco Services Company: Aramco Research Center—Houston) | Rueda, Jose I. (Saudi Aramco)
Hydraulic fracturing has been widely used in stimulating tight carbonate reservoirs to improve oil and gas production. Improving and maintaining the connectivity between the natural and induced microfractures in the far-field and the primary fracture networks are essential to enhancing the well production rate because these natural and induced unpropped microfractures tend to close after the release of hydraulic pressure during production. This paper provides a conceptual approach for an improved hydraulic fracturing treatment to enhance the well productivity by minimizing the closure of the microfractures in tight carbonate reservoirs and enlarging the fracture aperture.
The proposed improved fracturing treatment was to use the mixture of the delayed acid-generating materials along with microproppants in the pad/prepad fluids during the engineering process. The microproppants were used to support the opening of natural or newly induced microfractures. The delayed acid-generating materials were used in this strategy to enlarge the flow pathways within microfractures owing to degradation introduced under elevated temperatures and interaction with the calcite formation.
The feasibility of the proposed approach is evaluated by a series of the proof-of-concept laboratory coreflood experiments and numerical modeling results. First, one series of experiments (Experiments 1–3) was designed to investigate the depth of the voids on the fracture surface generated by the solid delayed acid-generating materials under different flow rates of the treatment fluids and different temperatures. This set of tests was conducted on a core plug assembly that was composed of half-core Eagle Ford Sample, half-core hastelloy core plug, and a mixture of solid delayed acid-generating materials [polyglycolic acid (PGA)] along with small-sized proppants sandwiched by two half-cores. Surface profilometer was used to quantify the surface-etched profile before and after coreflood experiments. Test results have shown that PGA materials were able to create voids or dimples on the fracture faces by their degradation under elevated temperature and the chemical reaction between the generated weak acid and the calcite-rich formation. The depth of the voids generated is related to the treatment temperature and the flow rate of the treatment fluids. Experiment 4 was conducted using two half-core splits to quantify the improvement factor of the core permeability due to the treatment with mixed sand and PGA materials.
Simulations of fluid flow through proppant assembly (inside of the microfractures) using the discrete element method (DEM)–lattice Boltzmann method (LBM) coupling approach for three different scenarios (14 cases in total) were further conducted to evaluate the fracture permeability and conductivity changes under different situations such as various gaps between proppant particulates and different depths of voids generated on fracture faces: (1) fluid flow in a microfracture without proppant, (2) fluid flow in a microfracture with small-sized proppants, and (3) fluid flow in a microfracture supported by small-sized proppants and generated voids on the fracture walls. The simulation results show that with proppant support (Scenario 2), the microfracture permeability can be increased by tens to hundreds of times in comparison to Scenario 1, depending on the gaps between proppant particles. The permeability of proppant-supported microfracture (Scenario 3) can be further enhanced by the cavities created by the reactions between the generated acid and calcite formation.
This work provides experimental evidence that using the mixture of the solid delayed acid-generating materials along with microproppants or small-sized proppants in stimulating tight carbonate reservoirs in the pad/prepad fluids during the engineering process may be able to effectively improve and sustain permeability of flow pathways from microfractures (either natural or induced). These findings will be beneficial to the development of an improved hydraulic fracturing treatment for stimulating tight organic-rich carbonate reservoirs.
Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Britt, Larry K. (NSI Fracturing) | Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Al-Attar, Atheer M. (Enterprise Products) | Trevino, Al-Hameedi (Missouri University of Science and Technology) | Al-Bazzaz, Waleed H. (Kuwait Institute for Scientific Research)
Drilling, completion, and stimulation designs have changed over time as a result of the oil and gas industry's ongoing efforts to increase well productivity. Over the last five years hydraulic fracturing treatments, represented by the volume of pumped water and the amount of proppant utilized, have increased significantly, along with the lengths of horizontal wells. This work represents a large-scale descriptive analysis study to illustrate the trends and the range of completion, stimulation and production parameters in the Marcellus Shale play of the Appalachian Basin between 2012 and the last quarter of 2017 (2012-2018).
A database was created by combing stimulation fluids and proppant data from the FracFocus 3.0 chemical registry, with completion and production data from the DrillingInfo database. More than 2000 Marcellus Shale wells were utilized in this study. The data were processed and cleaned from outliers. Box plots and distribution bar charts are presented for most of the parameters in this study, to show the range in values for each parameter and its frequency of use. The stimulation parameters were normalized to perforated lateral length in order to compare productivity between the wells.
Trends identified in this study show how operators in the Marcellus have increased the use of hybrid fracturing fluids, in addition to increasing water and proppant volumes over time. The work also illustrates the point at which increasing fracture treatment volumes no longer increases production rate.
This paper demonstrates the utility of integrating publicly available databases to examine well completion trends in the Marcellus. The work also provides a summary of well response as a function of treatment volume over the five year study period.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Belhaij, Azmi (Saudi Metal Coating Company) | Alkamil, Ethar H. K. (University of Basrah)
Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.
Asala, Hope I. (Louisiana State University) | Chebeir, Jorge A. (Louisiana State University) | Manee, Vidhyadhar (Louisiana State University) | Gupta, Ipsita (Louisiana State University) | Dahi-Taleghani, Arash (Pennsylvania State University) | Romagnoli, Jose A. (Louisiana State University)
The unsteady recovery of oil and gas prices in early 2017 led to an increase in drilling and hydraulic-fracturing operations in liquid-rich shale plays in North America. As field-development strategies continue to evolve, refracturing and infill-well drilling must be carefully combined to optimize shale-project profitability. Moreover, operators must bear in mind the undulating natural-gas demands persisting in an oversupplied shale-gas environment. In this paper, we use data-driven approaches to predict successful refracturing candidates and local gas demand for the second-tier optimization of a shale-gas supply-chain network.
A strategic-planning (SP) model is developed for optimizing the net present value (NPV) of a case-study shale-gas network in the Marcellus Play. This SP model uses a mixed-integer-nonlinear-programming (MINLP) formulation developed in the General Algebraic Modeling System (GAMS, Release 220.127.116.119). This model relies directly on input from reservoir simulation, local-gas-demand forecast, water-availability forecast, and natural-gas and West Texas Intermediate (WTI) crude-oil price forecasts.
Before reservoir simulation, machine learning (ML) is used to predict successful refracturing candidates, using a feed-forward neural network (NN), random-forest (RF) classifier, and a t-distributed stochastic-neighbor-embedding (t-SNE) visualization technique. Using the obtained results, best-practice field-development strategies are implemented in the area of interest (AOI) using reservoir simulation. Local gas demand is forecasted using a long-short-term-memory (LSTM) recurrent NN (RNN) that uses a multivariate data set created from local and global variables affecting shale-gas demand. A water-management structure is also developed for the optimization framework.
Using a 300-well data set (with 17 input features), successful refracturing candidates were proposed according to the joint outcome of an optimal 17/23/128/2 feed-forward NN, a t-SNE plot, and a techno-economic review. After ranking F1 scores, the developed NN outperforms the RF and support-vector-machine (SVM) algorithms for frac/refrac-well classification. The developed 32/256/128/120 LSTM model showed at least a 93% (+/-1%) prediction performance using three or five input features. The results illustrate the ability of the developed LSTM model to accurately predict local gas demands during periods of high or low gas demand.
After SP optimization over a 10-year planning horizon, the economic results indicate an NPV of USD 481.945 million, using the proposed physics-data-driven-based approach. An NPV of USD 611.22 million is obtained when no ML was used. The results reveal that the application of ML to strategic planning can prevent erroneous feedback of project profitability while allowing early-time decision making that maximizes shale-asset NPV.
Supporting Information included as a separate document below.
The combination of extended-length horizontal drilling and high volume hydraulic fracturing has led to previously unimaginable production increases, yet the recovery potential of unconventional oil and gas resources remains largely unrealized. Recovery factors for unconventional oil and gas wells are typically reported at < 20% in gas shale reservoirs and < 10% in the oil plays.
Neutrally buoyant ultra-lightweight proppants have been demonstrated to effectively provide production from fracture area that is otherwise unpropped and thus, non-contributive with conventional sand/slickwater hydraulic fracturing processes. Production simulations illustrate that treatment designs incorporating neutrally buoyant ULW proppant treatment designs tailored for contemporary unconventional well stimulations deliver cumulative production increases of 30% to over 50% compared to the typical large volume sand/slickwater treatments. Unfortunately, production simulation results may not sufficiently lessen risk uncertainties for operators planning high-cost multi-stage horizontal stimulations. Therefore, several field trial projects using the neutrally buoyant ULW proppant in extended-length horizontal unconventional wells are currently in progress to validate the production simulations.
Since the initial 4-stage fracturing stimulation incorporating neutrally buoyant ultra-lightweight proppant in 2007, deployment has occurred in fracture stimulating hundreds of oil and gas wells spanning multiple basins and reservoirs. Most of the wells are vertical or relatively short lateral wells common to asset development practices predating the unconventional shale completions mania, but many were targeted at the same unconventional reservoirs as the current multi-stage horizontal completions. Several published case histories have documented the production enhancement benefits afforded by the legacy ULW proppant wells, but questions remained as to how those lessons might be correlated to provide engineers confidence in the current production simulations.
Well completion and production information was mined from the various accessible databases for the neutrally buoyant ULW proppant wells. The scope of the legacy data compiled for analysis was limited to the reservoirs common to the current field trials and production simulations, ie. unconventional oil and gas shale reservoirs. Production performance contributions of neutrally buoyant ULW proppant in past applications were compared with the production uplift observed in applications and/or simulated application of neutrally buoyant ultra-lightweight proppant fracturing treatments in current multi-stage horizontal reservoirs.
The lessons learned from this investigation provide the practicing engineer the means to confidently assess production simulation data for multi-stage horizontal unconventional completions incorporating neutrally buoyant ulw proppant in the treatment designs.
Xu, Tao (Schlumberger) | Lindsay, Garrett (Schlumberger) | Zheng, Wei (Schlumberger) | Baihly, Jason (Schlumberger) | Ejofodomi, Efe (Schlumberger) | Malpani, Raj (Schlumberger) | Shan, Dan (Schlumberger)
During the downturn in the oil and gas industry, many operators have chosen to refracture their previously underperforming wells to boost economics with lower investment compared to drilling new wells. More than 100 horizontal wells have been refractured using chemical diverters across multiple basins in North America since the second half of 2013. Many papers have been published discussing these case studies. However, the refracturing results have been inconsistent. One of the biggest challenges of refracturing with chemical diverters is not knowing what is actually happening downhole. To understand what is happening better, more refracturing modeling should be performed to more reliably predict production results before spending the upfront capital for a refracturing treatment.
We propose a refracturing numerical simulation methodology to take into account the historical production depletion using the calculated pressure and stress measurements along the lateral and in the reservoir. The altered stress fields resulting from reservoir depletion are calculated through a comprehensive workflow coupling simulated 3D reservoir pressure with a geomechanical finite-element model described in a previously published paper. After the stress and pressure are updated, the new approach outlined in this paper is validated by production history matching real data from a previously refractured well in the Haynesville Basin to provide greater confidence in the end results. The main uncertainty in the process is how much of the lateral was stimulated. In this paper we also provide a sensitivity example to show how the model can be altered to predict different lateral coverage percentages.
Refracturing modeling still poses a major challenge for engineers because of the reservoir complexity and uncertainty downhole while refracturing (e.g., reservoir heterogeneity, isolation efficiency). However, our proposed refracturing approach provides a basic guideline on how to model refracturing treatments in a numerical simulator with the help of altered stress fields caused by reservoir depletion. This can be used to better understand why previously refractured wells perform the way they do and to better predict the performance of future refractured wells in both gas and liquid reservoirs.
Shale has been usually recognized as a transverse isotropic (TI) medium in conventional geomechanical log interpretation due to its laminated nature. However, when natural fractures (NFs) exist in the rock body, additional elastic anisotropy can be introduced, converting laminated Shale to an orthorhombic (OB) medium. Previous studies illustrate that treating the naturally fractured shale rock as a TI medium by ignoring the NF-induced anisotropy can cause the erroneous estimation of the geomechanical properties and in-situ stress. In this paper, the study is extended to quantify the impact of NF-induced elastic anisotropy on completion and fracturing designs in different actual shale reservoirs in U.S.
Published acoustic log data from five different shale formations (Bakken, Marcellus, Haynesville, Eagle Ford, and Niobrara) are collected and examined to determine their availability to generate the stiffness tensor of the representative TI background rock of each Shale reservoir. Natural fractures with different intensity values from 0 to 10 per foot, with shear wave splitting ranging from 0-5%, are introduced in the TI background rock to create the corresponding OB rock stiffness tensor. The OB stiffness tensors of different shale cases are finally converted back to the compressional and shear acoustic signals, which can be interpreted based on the TI or OB assumptions. The final output elastic moduli and in-situ stress results interpreted from different assumptions are compared, and the impact of NF-induced elastic anisotropy on completion and fracturing designs is quantified and fully understood for different shales.
The results show that introducing natural fractures into the TI background shale rock leads to a decrease of the in-situ stress and Young's modulus at the orientation perpendicular to the natural fracture plane. Such impact increases with increasing split of fast and slow shear wave slowness (SWS), while decreases with increasing ratio of the “soft mineral content” (i.e. clay and TOC) to the “hard mineral content” (i.e. quartz and calcite). In addition to that, different impacts on stress contrast (variation along the vertical depth) are observed for different shales, owing to the complex mineralogy/lithology sequences of different shale formations. As a result, ignoring the natural fracture induced elastic anisotropy in acoustic log interpretation can result in an overestimation of in-situ stress and Young's modulus as well as a misinterpretation of stress contrast, which further leads to the problematic or suboptimal completion/fracturing designs. The results have been also compared with the shale mineralogy/lithology log data to reveal how the natural fracture induced elastic anisotropy impact is associated with the natural fracture properties (compliance and intensity) and the mineralogy of TI background rocks.
The current study not only illustrates the importance of taking natural fracture induced anisotropy into account when performing geomechanical log interpretation, but also provides guidance to the operators of the five shale fields to better evaluate their current completion/fracturing design strategies and to determine if the natural fracture induced anisotropy impact should be corrected for their current designs or not based on the monitored splitting of fast and slow shear wave slowness.
ABSTRACT: It is important to determine well spacing for maximizing oil recovery in shale reservoirs with complex hydraulic and natural fracture geometries. The optimal number of well placement should be achieved to minimize well interference. Although there are many simulation studies to optimize well spacing, very few studies have been performed to combine the fracture propagation model and reservoir simulation considering complex fracture configurations. The goal of this study is to fill this gap by integrating a complex fracture model and reservoir model through a non-intrusive embedded discrete fracture model (EDFM) method. The fracture model was applied to predict complex fracture geometries. After that, such fractures were swiftly transferred to traditional reservoir simulators based on the non-intrusive EDFM technology. We applied the workflow to examine the effect of well number with varying well spacing on well performance in the Permian basin with and without considering natural fractures. Finally, the optimal well spacing was discussed. This study can provide key insights into optimization strategies for well spacing in shale reservoirs.
The optimal well number or well spacing plays an important role in economically developing shale or tight unconventional reservoirs. Well interference due to fracture hits often occurs if the well spacing becomes smaller, which should be minimized or avoided in order to maximize well productivity and economics (Lawal et al., 2013; King and Valencia, 2016; Kurtoglu and Salman, 2015; Liang et al., 2017; Yu et al., 2016, 2018a). Although there are many simulation studies to optimize well spacing (Díaz de Souza et al., 2012; Yu and Sepehrnoori, 2013; Tung et al., 2016; Manestar and Thompson, 2017; Mehranfar et al., 2018; Shahkarami et al., 2018) in unconventional reservoirs, most of them assume simple planar hydraulic fractures and did not consider the dynamic fracture propagation model to predict fracture geometry. In addition, the role of natural fracture in well spacing optimization is often ignored and poorly understood. Hence, it is of great importance to combine the fracture propagation model and reservoir simulation to evaluate the impacts of well spacing and complex hydraulic and natural fractures on well performance.
Summary We built a 3D geomechanical model using commercially available finite-element-analysis (FEA) software to simulate a propagating hydraulic fracture (HF) and its interaction with a vertical natural fracture (NF) in a tight medium. These newly introduced elements have the ability to model the fluid continuity at an HF/NF intersection, the main area of concern. We observed that, for a high-stress-contrast scenario, the NF cohesive elements showed less damage when compared with the lowstress-contrast case. Also, for the scenario of high stress contrast with principal horizontal stresses reversed, the HF intersected, activated, and opened the NF. Increasing the injection rate resulted in a longer and wider HF but did not significantly affect the NF-activated length. Injection-fluid viscosity displayed an inverse relationship with the HF length and a proportional relationship with the HF opening or width. We observed that a weak NF plane temporarily restricts the HF propagation. On the other hand, a tougher NF, or an NF with properties similar to its surroundings, does not show this type of restriction. The NF activated length was found at its maximum in the case of a weaker NF and at nearly zero in the case of a stronger NF and an NF that has strength similar to its surroundings. In this study we present the results for a three-layered 3D geomechanical model with a single HF and NF orthogonally intersecting each other, using newly introduced cohesive elements for the first time in technical literature. We also conducted a detailed sensitivity analysis considering the effect of stress contrast, injection rate, injection-fluid viscosity, and NF properties on this HF/NF interaction. These results provide an idea of how the idealized resultant fracture geometry will change when several fracture/fracture treatment properties are varied. Introduction The issue of HF and NF interaction has been numerically examined using software packages at both the laboratory and field levels. Warpinski and Teufel (1987) experimentally found that the HFs propagated through joints and formed a multistranded and nonplanar fracture network. The presence of a similar network was also observed in core samples from tight-sandstone reservoirs. Warpinski (1993) and Fisher et al. (2002) interpreted some of the Barnett Shale microseismic data and found that the HF propagation and orientation was affected by the already existing NFs. Lancaster et al. (1992) conducted a core study and found that the HF can propagate along an NF, resulting in propped NFs.
Xue, Xu (Texas A&M University) | Yang, Changdong (Texas A&M University) | Park, Jaeyoung (Texas A&M University) | Sharma, Vishal K. (Texas A&M University) | Datta-Gupta, Akhil (Texas A&M University) | King, Michael J. (Texas A&M University)
Summary Multistage hydraulically fractured horizontal wells provide an effective means to exploit unconventional reservoirs. The current industry practice in the interpretation of field response often uses empirical decline-curve analysis or pressure-transient analysis/rate-transient analysis (PTA/RTA) for characterization of these reservoirs and fractures. These analytical tools depend on simplifying assumptions and do not provide a detailed description of the evolving reservoir-drainage volume accessed from a well. There are no underlying assumptions of fracture geometry, reservoir homogeneity, and flow regimes in the method proposed in our previous study. It allows us to determine the well-drainage volume and the instantaneous recovery ratio (IRR), which is the ratio of the produced volume to the drainage volume, directly from the production data. In addition, a new w(s) plot has been proposed to provide better insight into the depletion mechanisms and the fracture geometry. In this paper, we build upon our previous approach to propose a novel diagnostic tool for the interpretation of the characteristics of (potentially) complex fracture systems and drainage volume. The w(s) analysis gives us the fracture surface area and formation diffusivity, while the IRR analysis provides additional information on fracture conductivity. In addition, quantitative analysis is conducted using the novel w(s) plot to interpret fracture-interference time, formation permeability, total fracture surface area, and stimulated reservoir volume (SRV). The major advantages of this current approach are the model-free analysis without assuming planar fractures, homogeneous formation properties, and specific flow regimes. In addition, the w(s) plot captures high-resolution flow patterns not observed in traditional PTA/RTA analysis. The analysis leads to a simple and intuitive understanding of the transient-drainage volume and fracture conductivity. The results of the analysis are useful for hydraulic-fracturing-design optimization and matrix-and fracture-parameter estimation.