Advancement in Hydraulic Fracturing for Improved Oil Recovery

Abstract

This chapter provides a comprehensive overview of advancements in hydraulic fracturing in unconventional plays. The narrative starts with an introduction to hydraulic fracturing and its transformative potential in the U.S., showcasing innovations in fracturing volumes, proppant masses, and well laterals. A detailed examination of fracturing fluids follows, emphasizing the dominance of slickwater treatments in unconventional plays. The chapter then delves into the crucial role of proppants, highlighting their surge in usage over a decade and the consequential shifts in material choice. The intricacies of perforation design are explored, particularly the revolutionary Xtreme Limited Entry approach and its subsequent impacts on production efficiency. In the realm of diagnostic technologies, the chapter presents a range, from traditional methods to emerging ones like Microseismic Depletion Delineation and time-lapse geochemical fingerprinting. The topic of refracturing is also addressed, spotlighting its merits in combating rapid production declines and the associated challenges. Finally, the chapter elucidates the phenomenon of fracture-driven interaction, offering insights into its historical context, influential factors, and proposed strategies to manage its repercussions. Through its breadth and depth, this chapter underscores the multifaceted nature of hydraulic fracturing advancements and their significance in the oil industry.

1. Introduction

In recent decades, the energy landscape has undergone transformative shifts, largely driven by advancements in drilling and extraction technologies [1]. Among these, hydraulic fracturing and horizontal drilling stand out as pivotal innovations that have revolutionized the field of unconventional reservoir exploitation in the United States [2]. These methodologies not only amplified production potentials but also ushered in a new era marked by constant technological advancements and optimizations. The upswing in hydraulic fracturing practices has catalyzed the inception of myriad new technologies, prompting in-depth, play-wide analyses that encompass a spectrum of reservoir characteristics and completion strategies [3]. Such analyses and innovations have borne fruit, with tangible increases in fracturing volumes, augmentation of proppant masses, and extensions of well laterals, leading to more efficient reservoir drainage and optimized production [4]. Figure 1 offers a comprehensive visual representation of the progression of these completion parameters across a temporal spectrum. Within the ensuing sections of this chapter, readers will be guided through a detailed exploration of these advancements, understanding the mechanics, the methodologies, and their profound impacts on production. Through this synthesis, the chapter aims to provide a consolidated understanding of the current state of hydraulic fracturing, setting the stage for future innovations and research in the domain.

Figure 1.

Evolution of lateral length, total fluid volume, proppant mass, and oil production with time through the Midland Basin (modified from Xu et al. [5]).

To navigate the intricate landscape of these advancements, this chapter unfolds as follows: We first delve deep into the design processes of hydraulic fracturing, tracing their evolution and significance in enhancing oil recovery. This exploration is supplemented by sub-sections focusing on the attributes of hydraulic fracturing fluids, the rising demand and adaptations of proppants, and the historical to modern developments in perforation design. Following this, we transition to a comprehensive examination of the diverse diagnostic techniques developed over the years, emphasizing their assumptions and limitations. The motivations, benefits, and challenges of refracturing existing wells form the subject of the subsequent section. We further explore the implications of fracture driven interaction in unconventional plays, discussing its history and strategies for mitigation. The chapter concludes by reflecting on the key findings and technological advancements, emphasizing their implications for future unconventional plays and the broader petroleum industry. Through this synthesis, we aim to provide a consolidated understanding of the current state of hydraulic fracturing, setting the stage for future innovations and research in the domain.

2. Completion design

2.1 Hydraulic fracturing fluids

The ideal fracturing fluid should meet several criteria. First, it must be compatible with both the formation materials and the fluids present. Additionally, it should have the ability to suspend and transport proppants deep into the fractures. Its inherent viscosity should be sufficient to create the required fracture width for proppant placement or for deep acid penetration. Efficiency is crucial, so the fluid should exhibit low leakoff. After its purpose is served, it should be readily removable from the formation. To ensure smooth operations, the fluid should generate minimal friction pressure and be straightforward to prepare on-site. Stability is another key characteristic; the fluid should maintain its viscosity throughout the treatment process. Lastly, while meeting all these criteria, it should also be cost-effective [6].

The use of slickwater (also called water frac or riverfrac) as the hydraulic fracturing treatment is the most popular approach in unconventional plays. This is mainly attributed to the simplicity of operations, ease of cleanup and lower cost [7]. On the other hand, the fluid has poor proppant transport properties due to its low viscosity. To overcome the transport challenges Zhao et al. [8] proposed a new type of fluid called High Viscosity Friction Reducer (HVFR). This new type of fluids has a low friction loss in the wellbore with good carrying capacity for proppant. This type of fluid system has gained a lot of popularity and have been applied in several basins to increase the proppant concentrations or increase the number of clusters per stage while ensuring good proppant transport capabilities [9, 10, 11, 12].

2.2 Proppant

During the decade from 2010 to 2020, the surge in unconventional horizontal well completions led to a sharp increase in the amount of proppant used in North America, as noted by Weijers et al. [13]. This sharp rise in demand necessitated a substantial amount of proppant, prompting the use of readily available and cost-effective brown sand.

The early days of unconventional formations using horizontal wells initially leveraged learnings from the fracturing principles of conventional formations. In an effort to minimize costs, there were initial attempts to completely exclude proppant from the treatment [14]. However, these attempt were not sustainable in the long run. Coulter et al. [15] demonstrated that enhancing proppant quantities in unconventional horizontal well stimulations considerably boosted immediate production. This pattern of escalating proppant volumes per well has been aggressively adopted by the industry. As a result, the amount of proppant being used in many unconventional formations is now in the range of thousands of pounds per foot of lateral [13]. After the oil price plummeted in late 2014, the industry pivoted toward using more voluminous quantities of lower-grade proppants. Both Brown and White Sand proppants are now commonly used in formations with closure stresses reaching up to 10,000 psi [16, 17]. To emphasize on proppant selection importance Pearson et al. [17] showed a time dependent conductivity losses. They used both numerical simulation, laboratory experiements and field data to shwo the importance of good near wellbore conductivity. They noted that adding 5–10% lead and tail high condcutivty ceramic proppant can lead to a significant increase in production and higher return on investment. Singh et al. [18] leveraged field scale laboratory experiemnts and field trials to suggest a Constant Concentration (CoCo) propant pumping schedule. They applied the technique on more than 100 wells using low concentration proppant without using gel in the hydraulic fracturing fluids. They reported that their wells had similar normalized performance when compared to wells varying proppant concentration.

2.3 Perforation design

Limited entry was initially introduced by Murphy and Juch [19] and Lagrone and Rasmussen [20]. The primary purpose of this technique was to ensure consistent flow rates across various perforations at distinct breakdown pressures. Subsequently, this approach was adapted for unconventional reservoirs to address the subsequent challenges [21]:

• Variability in stress along the lateral length (with approximately 90% of laterals falling within the 750 psi range).

• Fluctuations in near-wellbore friction from one cluster to another (with a median value of 625 psi from step-down tests).

• Stress shadow effect between clusters and from preceding stages (influenced by formation elastic properties).

• Irregular fracture propagation within different clusters and the anisotropy of elastic properties.

• Alterations in perforation friction due to erosion and a range of perforation diameters (around 500 psi).

Note that the values in brackets are values measured for the Bakken [21]. The pressure drop through perforation can be calculated as follows [22]:

$$\Delta P_p=\frac{0.2369\times Q^2\times \rho }{N_p^2\times D_p^2\times C_d^2}$$E1

where $\Delta P_p$, perforation pressure drop (pressure drop across perforation (psi)); $Q$, flow rate in bpm; $\rho$, fracturing fluid density (lb/gal); $N_p$, number of open perforations; $D_p$, perforation diameter (in); $C_d$, coefficient of discharge.

Weddle et al. [21] integrated the utilization of XLE (Xtreme Limited Entry) into their designs, leading to an increase in the cluster count from 11 clusters per stage to 15 clusters per stage, while maintaining a flow rate of 80 barrels per minute (bpm). The design involved a designated pressure drop of 2000 pounds per square inch (psi) at the perforations. The assessment of their achievements encompassed the analysis of data from fiber optic measurements, radioactive tracers, and production data.

For a lateral extent of 9500 feet, the authors managed to significantly reduce the total number of stages from 50 to 27, resulting in a pilot project that yielded an average incremental production increase of 10%. Notably, the authors highlighted the significance of considering plug shifting, which can induce leakage and subsequently compromise performance. The estimations related to proppant transport and settling velocity played a pivotal role in setting an upper limit on the number of perforation clusters feasible. Lorwongngam (Ohm) et al. [23] and Lorwongngam et al. [10] utilized eXtreem Limited Entry design to reduce the number of stages across the lateral to reduce the associated cost. They were able to increase the number of clusters per stage up to 15 then 20 with high unifromity index measured through Distributed Acoustic Sensing and downhole cameras.

To better understand the perforation design [24] conducted laboratory scale experiment. From their research, they concluded that perforation orientation has a significant effect on proppant placement. They reported that the response of proppant transprot is governed by a competion between viscous and gravity forces at lower rates, whereas at higher rates momentum effect become significant. Snider et al. [25] conducted field scale surface experiemnt. They reported that fluid placement and proppant placemnt are subject to different physics. Fluid placement is more uniform then proppant placement. With better unifromity for lower proppant size. The proppant distribution and errosion varied a lot in there testing. Dontsov [26] developed a mathemathical model to explain the physcis that governs proppant placement. He suggested that the proppant placement can explained by solving two subproblems: particle turning non unfirom proppant concentration in the wellbore. Using his mathemathical model he was able to match the previously mentioned experiments. He suggested that optimally the perforation orientation should be variable across the stage to ensure unifrom proppant placement; however since that is operationally challenging 90 degree orientation is the operationally optimum perforation orientation design [26].

3. Diagnostics technologies

Different fracture diagnostic techniques have been developed over the years to be able to characterize key fracture property. Each diagnostic approach has its own assumptions, limitations and key parameters. Barree et al. [27] described how to leverage early diagnostic techniques in evaluating the stimulation treatment. Microseismic can be used as a proxy for fracture geometry. As fractures propagate, they change the pressure distribution across the formation. This leads critically stressed natural fractures to slip generating a microseismic event. Fracture geometry (height, length, azimuth, and asymmetry) is then inferred from the combination of these events. Microseismic events generated the initial understanding of unconventional plays. The oil and gas industry used to think that generated system underground is a complex fracture network of fractures activated in different directions [28]. However, with the advancement of fracture diagnostic technology (Fiber optic), fractures were proven to be parallel plate fractures [29] as part of Hydraulic Fracturing Test Site (HFTS) project funded by the Department of Energy. Apparent discrepancies were noted at this project where microseismic events did not show fracture propagation, However the fracture propagation was felt by the strain on the offset well fiber optic.

Fiber optic was used in-well and offset wells for different purposes. The in-well fiber optic is used to evaluate the seal between two stages [23] or to quantify uniformity index between different clusters of the same stage [30, 31]. Jin et al. [32] utilized in-well fiber optic to quantify conductivity changes and fracture response during production. For offset well fiber optic usage, Dhuldhoya and Friehauf [33] used the technology for measuring far field uniformity and fracture length. Pudugramam et al. [34] used offset well fiber to estimate fracture height at the HFTS-2 project. Haustveit and Haffener [35] used fiber technology and bottom hole gauge to infer a relationship between pressure drawdown and fiber strain using polynomial function fitting.

Haustveit et al. [36] introduced Sealed Wellbore Pressure Monitoring as a low expense diagnostic approach to measure fracture driven interaction response at offset wells. It can be used for qualitatively assessing cluster efficiency, fluid distribution, estimate fracture height, and length. Identify depletion and estimate fracture closure time. It relies on monitoring deformation of a sealed wellbore. Once deformation occurs a pressure response is measured pressure gauge. The approach was validated using fiber optic in several basins [37, 38]. This technique was also used to calibrate fracture models using the volume to first response [39]. The volume to first response (VFR) is the volume injected before any pressure response is noted at offset wells. Smaller volumes are attributed to non-uniform fluid distribution as one fracture propagates faster than the others resulting in small VFR. This concept is illustrated in Figure 2. The left side of the figure depicts a high volume to first response, associated with a good distribution of fluids that delays the time for the first fracture hit to occur. Conversely, the right side shows a low volume to first response, indicating poor uniformity in fracture propagation. In this scenario, one fracture consumes more fluids and propagates, while other fractures remain stagnant.

Figure 2.

Conceptual idea of first volume response modified from Haustveit et al. [38]. The figure in the left shows high volume to first response. This is associated with a good distribution of fluids delays the time for the first fracture hit to occur. On the right a low volume to first response illustrates a poor uniformity in fracture propagation as one fracture took more fluids and propagated whereas other fractures did not propagate.

Another diagnostic that leverage microseismic events is Microseismic Depletion Delineation (MDD). It was first introduced by Dohmen et al. [40]. The concept of the idea relies on poro-elastic stress changes due to depletion. As stress changes more the Mohr Columb failure criterion for different fractures shifts into critically stressed fractures. The operator injects a small volume of fluid to activate these critically stress fractures to map the stress state in the reservoir [41, 42]. The stress state is a proxy of the depletion areas. This concept is visually captured in Figure 3, which presents the Mohr-Coulomb failure criteria. The figure on the left illustrates the stress state after depletion, with optimally oriented natural fractures on the brink of slipping. However, upon water injection, the stress state undergoes a shift, as depicted in the figure on the right. This results in fracture slippage, generating microseismic events. These event are collocated at depleted zones. This approach have been applied several times to map the drainage area of parent wells in the Bakken and optimize well spacing of infill wells [43, 44].

Figure 3.

Mohr-Coulomb failure criteria (left) stress state and natural fracture orientation after depletion, (right) stress state and fractures failure due to injection. The figure in the left shows the stress state after depletion. The natural fractures optimally oriented are about to slip. Once the water is injected the stress state shifts as illustrated in the figure in the right and the fractures slips generating microseismic events.

Michael et al. [45] introduced a new diagnostics approach for mapping drained reservoir volume and dynamic production allocation by intervals through time in unconventional reservoirs. In their approach they leverage time-lapse geochemical (TLG) fingerprinting of formation fluids (gas, oil, and water). The approach relies on the unique biomarker signatures of each formation and their corresponding appearance in the produced fluids. This approach was used to optimize the landing depth and quantify the contribution of each member of the formation [46, 47]. Bachleda et al. [48] utilized the approach to build a proxy for EUR predictions in the Anadarko Basin. Maxwell et al. [49] leveraged the use of TLG and microseismic data to conceptually understand the effective drained fracture height.

Diagnostic Fracture Injection Test (DFIT) is a very popular diagnostics approach implemented in Unconventional plays. It consists of injecting small volumes into the wellbore to create a small fracture. The pressure/temperature response is then recorded to infer the formation least principal stress, formation permeability and formation pore pressure. Barree et al. [50] proposed an approach for the interpretation of DFIT tests. This approach have been widely used in the industry; however it have been criticized for the lack of physics based supporting evidence. McClure et al. [51, 52] identified issued with the holistic approach [50] and suggested a new interpretation scheme called the compliance method. McClure et al. [52] approach is specifically designed for low permeability formations and have been tested using field experiments and statistical approaches to outperform the holistic approach [53, 54, 55, 56].

An interference test is a procedure in which one or more wells are sequentially brought into production, while the pressure is monitored in one or more nearby shut-in wells. By observing the pressure changes in the shut-in wells after each active well starts production, the degree of connectivity or communication between neighboring wells can be assessed. This type of tests is mainly used to determine optimum well spacing [57]. Well spacing decisions, both lateral and vertical, are fundamental for achieving economic efficiency in shale formations. While more densely spaced wells might result in reduced production and return on investment (ROI) per individual well, they can enhance the overall production and Net Present Value (NPV) for a specific land section [58].

Chu et al. [59] proposed an interpretation approach for interference tests. The approach have been applied in several basins [60, 61]. The approach quantifies a factor called Chow Pressure Group (CPG). The closer CPG is to 1 the higher the connectivity. The lower the CPG (less than 0.5) the lower the connectivity between wells [62]. Almasoodi et al. [63] reported that The CPG (Cross-Well Pressure Gradient) has certain limitations, including the inability to provide a quantitative estimate of how a well’s production is affected by neighboring wells. Additionally, it is uncertain whether the same value of CPG, when measured between two wells, consistently indicates the same level of production interference, regardless of variables such as reservoir properties, fluid characteristics, or test conditions. They utilized analytical approach and numerical simulations to develop a physics-based interference interpretation approach (so-called Deveon Quantification Interference (DQI)). They have also applied the approach to different wells yielding consistent results.

4. Refracturing

Unconventional oil and gas wells frequently face rapid production declines. Historically, the industry’s response has been to drill and fracture new wells. However, with recent oil price downturns, there’s an escalating interest in refracturing, or restimulation, of existing wells to enhance their productivity. The objectives of refracturing are to increase the production of hydrocarbons from existing wells and improve their profitability [64]. This type of operations can result in an incremental production of 30–70% [65]. However, the success rate of refractured wells is relatively low, with only 15–20% of wells achieving the desired improvement in practice [65]. Therefore, one of the objectives of advanced studies in this area is to develop reliable and systematic approaches to increase the success rate of refracturing jobs.

Data analysis techniques and fuzzy clustering has been proposed for the selection of refracturing candidates, guiding the development of tight oil and gas reservoirs effectively [66]. Near-wellbore diversion is commonly used to ensure a uniform fluid and proppant distribution (particulate diversion, perforation sealing, and mechanical isolation [67]). The Barnett Shale has seen the application of multiple refracturing techniques, including bullhead treatment with and without diverter, various types of diversion, and mechanical isolation [68]. In Daqing Oilfield, refracturing has been employed to address the declining output of tight reservoirs. Different refracturing modes have been developed based on initial fracturing parameters and completions [69]. The Fuling shale gas field in China witnessed the first successful application of a Casing-in-Casing (CiC) refracturing treatment, providing a new option for refracturing horizontal wells in the region [70]. The use of biodegradable particulate diverters in hydraulic fracturing and refracturing has shown potential in increasing production and improving overall well economics, though their effectiveness can vary, especially in horizontal wells [71]. Another study on “blind” refracturing in horizontal wells in low-permeability reservoirs highlighted the potential of hybrid reinforcement, combining steel and basalt fiber-reinforced polymer (BFRP), which could increase the bearing capacity of samples by 33–74% [72].

Refracturing faces challenges such as limited options leading to increased costs and potential well loss. Current solutions include cementing perforations, expandable steel liners, biodegradable materials, and coiled tubing straddle packers, each with its own set of limitations. A promising approach is the reclosable sleeve technology, offering stage-by-stage access and maintaining wellbore integrity. These sleeves can be cycled open and closed during various well operations, providing flexibility in refracturing and production phases. However, their long-term effectiveness in refracturing remains to be fully validated [73]. The success of these refracturing techniques hinges on various factors, including the judicious selection of wells and determining the ideal timing for the procedure [65]. In reservoirs with natural fractures, understanding and predicting stress redistribution due to the poroelastic effect becomes intricate, making it crucial for optimizing refracturing performance [74]. Additionally, in areas like the Sulige Gasfield, wells with hydraulic fracturing have exhibited rapid decline rates, and the new fractures introduced during refracturing might not always align with the direction of the original fractures [75]. Additionally, selecting the optimal wells for refracturing is a primary challenge. Factors affecting the selection of refracturing candidates for multi-fractured horizontal wells are numerous and their relationships are complicated, making it difficult to choose the best wells [76]. The challenges of well refracturing include stage isolation, the complexity of the fracture system, candidate selection, understanding the rock system, refracture deviation, and uncertainty in predicting production results. These challenges highlight the need for careful planning, evaluation, and modeling to ensure the success of refracturing treatments.

5. Fracture driven interaction

To maximize the Estimated Ultimate Recovery (EUR) from unconventional plays, the design of hydraulic fracturing has observed tendency for larger fluid and proppant volumes and closer cluster spacing. However, these approaches led to a serious challenge known as fracture-driven interaction (FDI), also called frac bashing or frac-hit [77, 78, 79]. The first drilled well in unconventional is called primary or parent well, and the following drilled wells are called offset or child well. FDI refers to the inter-well communication between two wells.

The very first documented works in unconventional go back to Ajani and Kelkar [80] and Daneshy et al. [81]. Gupta et al. [82] reported a thorough literature review about different aspects of fracture driven interaction. They summarized different factors that influence the FDI response. The factors have been categorized into changeable and unchangeable. The changeable parameters are well placement, completion, and depletion; whereas several parameters are out of our control and are defined by the characteristics of the play. The unchangeable factors are divided into geological features and rock properties. The geological features consist of natural fractures, faults, bedding planes, fracture barriers, in situ stresses, rock fabric, and mineralogy. The rock properties consist of Young’s modulus, Poisson’s ratio, matrix permeability and porosity, fracture toughness, pore pressure, Biot’s coefficient, and tensile strength.

Several authors worked on the influence of depletion on the occurrence of fracture driven interaction [43, 80, 82, 83, 84, 85, 86]. Depleting the primary well creates a low-stress area due to the poro-elastic response of the rock mass. When the fracture propagates from the offset well, a low-stress zone around the primary well causes an asymmetric growth of these fractures toward the lower stress area of the primary well [85, 87, 88, 89].

Jacobs [90] reported several completions strategies to avoid fracture driven interaction. He suggested the following practices with their limitations:

• Reduce the size of the offset well completion: This will reduce the capital invested and frac-hit occurrence; however, it can lead to an under-stimulated reservoir volume.

• Increase the size of the offset well completion: This will reduce the asymmetric growth of infill well fractures; however, it can lead to undercapitalization.

• On-the-Fly completions: also suggested by Daneshy [91], aims to adjust completion in the field according to measured data from the monitoring well. The difficulty is that this approach is technically challenging.

• Pinpoint/coil completion: It uses a single cluster to have more control over the fluid distribution; however, it can lead to smaller stimulated volume due to the limited number of clusters.

• Staggered wells, cube development, or rolling development can be implemented to either reduce the severity of the interaction or eliminate the depletion effect.

Fracture driven interaction was also investigated using numerical modeling approaches to understand the wells performance and how wells interact with each other’s. Ratcliff et al. [92] modeled production losses due to fracture driven interaction in the Anadarko basin using a conductivity damage function. Fowler et al. [93] summarized the potential explanations for production uplifts [43, 94] and production losses [82]. McClure et al. [55, 56, 58] reported results from a cross basin collaborative study on modeling fracture driven interactions effect on production. They history matched several cases and suggested optimized scenarios for better wells development.

6. Challenges of hydraulic fracturing

The progression of hydraulic fracturing resulted in more questions then answers. Several areas of investigations are still open. The microseismic response explanation and interpretation are still ambiguous especially when compared to fiber optic [95]. The fracture driven interaction response in different plays [82] and their origin is another area of research to explain remediation approaches. Another challenge is the explanation of sub-parallel fractures that were noticed in [96]. Savitski [97] attempted to explain these responses; however, this area requires further investigation. One of the important challenges is the casing seal between stages. These isolation are provided through plugs and cement [98, 99]. Hydraulic fracturing propagation mechanisms in different setting is still a topic of discussion and several authors have reported a different way into solving the challenge [100]. This is still an area of active research. Furthermore, there is a room for proppant and completion selection criteria research to step in and utilize data analytics to improve prediction [101, 102].

7. Conclusion

The landscape of hydraulic fracturing has undergone a remarkable evolution over recent years, solidifying its role as a cornerstone in modern reservoir engineering practices, particularly in unconventional plays. From the nuances of fracturing fluid selection, which ensures compatibility and effective proppant transport, to the intricate science behind perforation design that optimizes production, we witness a confluence of innovations. The surge in proppant usage, and the resultant shifts in material choices, underscores the industry’s adaptability to emerging challenges and market dynamics. Diagnostic technologies, with their breadth from early methodologies to novel techniques like Microseismic Depletion Delineation, stand testament to the relentless pursuit of more accurate reservoir characterizations. Refracturing emerges as a promising avenue to rejuvenate wells facing production declines, though it carries its own set of challenges which the industry is keenly addressing. Perhaps, one of the most significant takeaways from this chapter is the intricate dance of inter-well communication encapsulated by fracture-driven interaction. Its implications, both in terms of reservoir performance and economic outcomes, necessitate meticulous planning and agile execution strategies. As we move forward, it’s evident that the industry’s success will pivot on a deeper understanding of these elements, combined with a commitment to innovate and refine practices. The future of hydraulic fracturing, thus, promises to be as dynamic and transformative as its storied past.