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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.
Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Britt, Larry K. (NSI Fracturing) | Dunn-Norman, Shari (Missouri University of Science and Technology) | 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)
The goal of any hydraulic fracturing stimulation is to design and execute the appropriate treatment that is best suited for the stimulated reservoir. Selecting the best treatment must achieve the desired fracture geometry to maximize long-term well productivity and reserve recovery. The main objective of this study is to conduct detailed short and long-term production and well-to-well comparisons of the different types of fracture stimulation fluids in the Marcellus Shale play.
A database of more than 4,000 wells was integrated for this study. The wells were divided into four groups: water, gel, cross-linked, and hybrid fracs. Chemical data from FracFocus were gathered and processed then coupled with completion and production data to investigate the gas short and long-term production. Detailed monthly production data for the participating wells were captured from DrillingInfo database and utilized in this study.
This paper reports and compares the Marcellus gas initial production, the gas cumulative of the first month, first 6 months, first year, 2 years, and 5 years. The well productivity is tied to each hydraulic fracturing fluid type. The paper provides insights into the different completion trends in the Marcellus as well as the variations in stimulation parameters such as the volume of stimulation fluid and the amount of pumped proppants. The completion aspects of perforated lateral length are also taken into consideration and a comparison of the normalized production and stimulation parameters is also presented. The study shows that water fracturing fluids outperformed the other types of hydraulic fracturing fluids.
This paper introduces several data processing workflows that serve as a reference for individuals who are interested in mining and processing FracFocus database. It also documents the change in hydraulic fracturing fluid types and measures the effects of the fracturing fluid volume and total proppant pumped on the initial and cumulative production.
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.
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.
Hydraulic fracturing has been widely used for unconventional reservoirs, including organic-rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source-rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate-source-rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source-rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy-dispersive spectroscopy (EDS), were used to investigate the source-rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing-fluid treatments.
The SEM and EDS results before and after fracturing-fluid treatments on the source-rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of the aperture for pre-existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater-fluid-treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core-plug samples. This effect on absolute-gas-permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidence at different scales that aqueous-based fracturing fluid might potentially have a positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater-and seawater-based fluids in stimulating gas production from organic-rich carbonate formations.
Kumar, Abhash (AECOM, National Energy Technology Laboratory) | Zorn, Erich (National Energy Technology Laboratory (currently with DiGioia Gray Inc.)) | Hammack, Richard (National Energy Technology Laboratory) | Harbert, William (University of Pittsburgh)
Hydraulic fracturing is a well-established technique to extract gas or liquid hydrocarbons from low-permeability formations such as shale and tight gas reservoirs. Diffusion of hydrofracturing fluid outward from the stimulated fractures into the target formation produces slip across pre-existing fractures and other discontinuities in the rock. Microseismic events recorded by downhole seismic-monitoring arrays are a manifestation of associated deformation. Recent investigations suggest that the total cumulative seismic moment of microearthquakes during hydraulic fracturing is only a small portion of the total seismic-energy release expected for the fluid volume injected into the formation. These observations suggest that other sources of energy release (such as inelastic deformation), contemporaneous with microseismicity, should be considered relevant to the hydraulic-fracturing process. Recent observations on long-period, long-duration (LPLD) seismic events suggest that slow slip emission along weaknesses that are misaligned with respect to the present-day stress field is likely an important mechanism of deformation and should be better understood and quantified in reservoir stimulations. In Morgantown, West Virginia, we conducted seismic monitoring of hydraulic-fracturing activity using an array of five broadband, three-component (3C) surface seismometers. Using this network, we identified 89 high-amplitude, impulsive events and 436 LPLD events, with highly emergent waveform characteristics. In these interpreted LPLD events, we observed a significant concentration of energy in the 0.8- to 3-Hz frequency range. During hydraulic fracturing, LPLD events were found to occur most frequently when the pumping pressure and rate were at or near maximum values. Because the main purpose of hydraulic fracturing is to stimulate oil and gas production from the less-permeable reservoir, we compared the relative production contributions/stage to the frequency of the occurrence of suspected LPLD events. We found a positive correlation between the frequency of LPLD events and stage-by-stage gas production, highlighting the potential contribution of slow deformation processes and its effectiveness in the reservoir stimulation.
This paper presents a rigorous method to scale rate-time profiles of multi-fractured horizontal wells (MFHW) to a set of reference reservoir and completion properties. Scaling is required for development of accurate production forecasts and typical well production profiles (type wells) with minimum uncertainty.
We use a modified version of commonly-used type curves, notably the Wattenbarger type curve, to fit production data. The fit requires that production profiles exhibit a negative half slope during transient linear flow followed by negative unit slope during boundary-dominated flow on a rate vs. material balance time plot. The horizontal and vertical displacement required to fit observed data to the type curve define the scaling factors for individual wells.
We present a set of equations to scale a given well's production profile to that of a reference well with specified effective permeability, fracture length, lateral length, net-pay thickness, drawdown, and fracture stage spacing. Just as we can scale a group of wells to common reference conditions, we can also rescale to predict the performance of a well with specified properties, such as average properties determined from wells analyzed or wells with completion designs different from those analyzed. While it is common and clearly important to normalize (scale) rate profiles for lateral length, we demonstrate that it is also crucial to scale production profiles in rate and time to account for differences in permeability, fracture spacing and thus, the duration of flow regimes. We provide examples of successful scaling based on publically reported production data from Marcellus, Barnett, Niobrara, Midland Basin (Wolfcamp) and Eagle Ford resource plays.
Most of the methods used to assess the performance of MFHW's in resource plays rely on having a statistically significant number of analogs. However, datasets of sufficient size are often either unavailable or limited by the large variety of completion designs and well performance characteristics. Our approach to scale production can dramatically increase the number of analogs available to characterize a geologically similar area and thus reduce the uncertainty in production forecasts.