Fracture Stimulation Research Articles

Fracture propagation characteristics of layered shale oil reservoirs with dense laminas under cyclic pressure shock fracturing

Forming a fracture network through fracturing stimulation is significant to efficiently developing shale oil resources. However, the complex lithological characteristics and dense laminas of continental shale oil strongly shield fracture propagation. The concept of "cyclic fluid injection induces rock fatigue" was introduced into shale oil fracturing technology, and the cyclic pressure shock fracturing method was designed. The horizontal well fracturing simulation experiments used prepared shale rock samples from the Permian Lucaogou Formation shale oil reservoir outcrop in Jimusar Sag, Junggar Basin. Two pressurization states were obtained through constant injection and rapid release of accumulated high pressure, corresponding to conventional and pressure shock conditions. The characteristics of fracture propagation under different fracturing methods were analyzed by combining acoustic emission monitoring and injection pressure curve response. Research has found that the dense laminas with a certain original width near the wellbore significantly inhibit the vertical propagation of hydraulic fractures (HFs), and conventional constant-rate fracturing methods make it difficult to stimulate the reservoir effectively. Fatigue fracturing can increase the complexity of near-wellbore fractures, but the HFs still tend to be arrested by the laminas. The bottom hole pressure (BHP) is artificially increased to a value far exceeding the rock breakdown pressure near the wellbore by applying the cyclic pressure shock fracturing method. It can avoid the communication between micro-cracks and horizontal laminas during the BHP constant rate increase process and overcome the inhibition of weak layers on vertical propagation. Besides, the fracture height and number of activated laminas positively correlate with the number of cycles. When the shock pressure is about 30 MPa, the fracture height of the three cycles increases by 50% compared to a single shock. In addition, the shock pressure has a more significant effect on the fracture height, and the fracture height increases significantly with the increase of shock pressure. The shock pressure increased by about 57%, and the fracture height increased by 60%. High-pressure shock has a certain effect on the naturally weak surface of the far well, which may cause the slip of the weak surface to produce AE signals. This provides a new approach for improving fracture complexity and control volume in layered shale oil reservoirs with dense laminas.

Study on the hydraulic fracture extension pattern of Gulong Shale Oil Reservoir in Songliao Basin

This study aimed to investigate the fracture extension pattern of the Gulong shale oil reservoir through rock mechanical tests, fracturing physical simulation experiments, and on-site tracer fracture monitoring to enhance fracturing stimulation effectiveness. The results of the rock mechanical tests revealed the anisotropic mechanical properties of the rocks attributed to the lamellation structure. Fracturing physical simulation experiments were conducted to determine the fracture extension pattern in the laboratory, indicating that increasing the fracturing fluid viscosity and injection rate could help overcome the vertical extension limitations caused by the lamellation structure. For the first time, on-site tracer fracture monitoring was implemented to study the hydraulic fracture extension pattern of the Gulong shale oil reservoir. The findings suggested that utilizing stages with three or four perforation clusters, a 50% slick water ratio, and temporary plugging could enhance fracture initiation efficiency and promote uniform extension. After modifying the parameters based on the research results, the on-site fracturing wells exhibited excellent fracturing stimulation effects. This study is significant for understanding the unique fracture extension pattern of the Gulong shale oil reservoir both in laboratory settings and on-site, providing technical recommendations for improving fracturing stimulation in other reservoirs with similar characteristics.

Seismic anisotropy of granitic rocks from a fracture stimulation well at Utah FORGE using ultrasonic measurements

For effective fracture stimulation in Enhanced Geothermal Systems (EGS), characterization of subsurface rock elastic properties is essential. Because seismic anisotropy significantly influences hydraulic fracturing, locating and characterizing microseismic events, and forecasting stress trajectories, our research undertakes laboratory experiments to study seismic anisotropy parameters of core samples from the Utah FORGE EGS site. We evaluated two rock samples from well 58–32, at two depths of 2074.16 m (6,805 feet) and 2268.01 m (7,441 feet), respectively. We analyze the mineralogy and classify the shallower rock as syenogranite, and the deeper rock as orthogneiss and monzonite. We cut cylindrical plugs from these two core samples, imaged them by computed tomography (CT) X-ray imaging, and measured their seismic anisotropy using ultrasonic waves at 1 MHz and under varying confining pressures (5–50 MPa) in ambient temperature conditions. With the assumption of the transversely isotropic (TI) medium, we measured three P-wave velocities and two S-wave velocities along different propagation directions to compute the Thomsen anisotropy parameters. Our results showed that the measured seismic velocities of each rock sample increase with increasing effective pressures, a behavior likely caused by closure of microcracks identified in our CT images. We also find that the measured anisotropies are higher at lower effective pressures. The maximum measured anisotropies for P-waves and S-waves are ∼23% and ∼20%, respectively. Therefore, we expect in the field operation that anisotropy should increase with increasing pore pressure caused by injection, which could be valuable in future EGS reservoir management and monitoring.

Present-day stress regime, permeability, and fracture stimulations of coal reservoirs in the Qinshui Basin, northern China

Present-day stress regime, permeability, and fracture stimulations of coal reservoirs in the Qinshui Basin, northern China

Fracture stratigraphy in oil-rich shale of the Upper Xiaganchaigou Formation (upper Eocene), western Qaidam Basin

Natural fractures in wells from oil-rich shale of the Upper Xiaganchaigou Formation in Qaidam Basin, the largest Cenozoic sedimentary basin in the Tibetan Plateau, vary systematically by stratigraphic position, allowing reconstruction of fracture generation processes during regional tectonic deformation. Compacted fractures, layer-bounded fractures, and low-angle (or bed-parallel) fractures were widely identified in oil-rich shale cores obtained from vertical wells. The layer-bounded fractures can be subdivided into two sets: one prevalent in light-colored (low gamma-ray) stiff layers and arrested by dark-colored (high gamma-ray) compliant layers, the other set primarily confined to the dark-colored compliant layers. The strikes of layer-bounded fractures, revealed by horizontal well FMI logs, are dominantly N60°-80°E and N10°-30°E within the light and dark intervals respectively. These strikes are consistent with natural hydraulic fracturing of the light layers during the Oligocene and the dark layers during the Middle Miocene-Holocene, based on a regional anticlockwise rotation of the compressional strain orientation. The abutment of layer-bounded fractures against low-angle (or bed-parallel) fractures in dark layers implies that the low-angle fractures were hydraulically fractured under a vertical least compressive stress during the Early Miocene, which produced the most intense tectonic compression. Layer-bounded fractures generally remain unmineralized in the dark layers but were mineralized in the light layers, suggesting that fractures confined in light layers would not decrease the sealing capacity of the shale oil system and fractures confined in dark layers can increase the pore space of shale oil storage. The Oligocene and Early Miocene fractures represented mechanical flaws that affected the initiation of Middle Miocene-Holocene fractures, implying that all natural fractures may alter hydraulic fracture stimulations to some extent.

Technology Focus: Unconventional and Tight Reservoirs (July 2024)

Unconventional reservoirs bear a unique perplexity in that, at every scale, they are different from their conventional counterparts and even one another. Small nuances in any one parameter can result in a vastly different well result, which may affect how an area, or even an entire play, is interpreted. This month’s selection of papers is all about those differences, in recognition that it is technology that drives innovation through understanding what these differences mean and how best to extract value from these vast resources. Starting at the well scale and looking at the benefits of knowing the efficacy of each stimulation stage, paper URTeC 3864145 is from the Ordos Basin in China. Investigating hydraulic fracture performance on a stage-by-stage basis proves time and time again that understanding the details can improve overall development outcomes. The case study reviews two hydraulic fracture diagnostic techniques used in combination to determine water breakthrough and shutoff plans. Zooming out to the play scale, paper SPE 216292 is focused on the most variable of unconventional reservoirs: the carbonate reservoir. This case study of the Austin Chalk formation in Texas analyses the production uplift from application of horizontal, multistage fracture stimulation technology in tight or fractured carbonate reservoirs. The application of unconventional technology in carbonate reservoirs can extended field life, and the deployment of this technology should be considered for any redevelopment or reassessment of potential resources trapped in tight carbonate reservoirs. Finally, paper OTC 34832 draws on the concept of innovation that is required to unlock unconventional resources. Novel methods of stimulation are the cornerstone of unconventional technology in that well stimulation is a basic requirement of all low-permeability reservoirs. The paper describes a trial pilot from idea through execution from Kuwait Oil Company for enhanced oil recovery in tight formations using downhole hydrogen generation from in-situ exothermic multistage chemical reactions between two unique hydroreacting agents. The paper also provides lessons learned and optimization insights from the trial, concluding that a successful, low-cost alternative stimulation technique was demonstrated and repeatable. Recommended additional reading at OnePetro: www.onepetro.org. SPE 216139 Tight Gas Reservoir Characterization and Comparison of PLT Methods: Microseismic Monitoring, Fiber-Optical Production Logging, and Tracer-Coated Sand Monitoring Applied in the Same Well by Xiao Yao, Petrochina, et al. SPE 216149 New Insight in Developing Tight Fractured Carbonate Reservoirs, Mishrif Formation, West Kuwait by M. El-Jeaan, Kuwait Oil Company, et al. SPE 215712 Successful Utilization of In-Situ Dune Sands in Saudi Arabian Unconventional Frac Operations by Nahar Qahtani, Saudi Aramco, et al.

Assessing hydraulic fracturing feasibility in marine hydrate reservoirs: Impact of closure pressure and hydrate decomposition on fracture conductivity

Hydraulic fracturing is a potentially promising technology for stimulating gas production and improving energy efficiency in low-permeability hydrate reservoirs. However, marine hydrate reservoirs, with weak cementation, unconsolidated nature, low mechanical strength, and the potential for decreased strength and fines migration resulting from hydrate decomposition, pose significant challenges for effective fracture propping and maintaining high conductivity. To assess hydraulic fracturing feasibility in marine hydrate reservoirs, we conducted experiments to investigate the impact of closure pressure, hydrate saturation, and hydrate decomposition mode on fracture conductivity, with a particular focus on understanding the propping mechanism and identifying potential sources of conductivity damage in artificial fractures. The results demonstrated that the conductivity of propped fractures within hydrate-bearing clayey silt sediments linearly decreased with increasing closure pressure, primarily due to proppant compaction and embedding. The conductivity disparity under different hydrate saturation levels decreasesd and became similar at 16 MPa closure pressure. The decomposition mode of hydrates had a significant impact on fracture conductivity damage, with higher degree of damage observed with increasing depressurization range (up to 90.3% at a 3.0 MPa range), whereas slow decomposition induced by heating only resulted in minor decreases in fracture conductivity (damage degree: 6.6%), primarily attributed to the migration of fine particles during gas-water production. Proppant embedding and fines migration were the main causes of fracture conductivity damage in hydrate reservoirs. Proppant embedding damage occurred at higher closure pressures or slow hydrate decomposition, while fines migration damage occurred with rapid hydrate decomposition. In proppant-filled propped fractures, fines migration posed a greater risk to fracture conductivity than proppant embedding, as the migration of fine particles can block the pore spaces within the proppant-filled fractures, leading to a significant reduction in conductivity. Therefore, it was recommended to induce hydrate decomposition by slowly reducing pressure during production to minimize fines migration damage to fracture conductivity. These research findings hold significant importance in the application of hydraulic fracturing during field tests conducted on hydrate reservoirs, as they assist in optimizing the propping mode of fractures and ensuring the effectiveness and prolonged success of fracturing stimulation.

Characterization of low-frequency distributed acoustic sensing signals in hydraulic fracturing stimulation – A coupled flow-geomechanical simulation approach

Low-frequency distributed acoustic sensing (LF-DAS) is one of the promising diagnostic techniques for detecting and characterizing hydraulic fractures. LF-DAS signals can capture fracture hits and the strain field around the hydraulic fracture. However, the interpretation of field LF-DAS data can be challenging due to the complexity of the underground conditions. This study develops a fracture propagation model to simulate the hydraulic fracturing process. The modelling results are analyzed to examine patterns and trends observed in interpreting field LF-DAS data. The fracture propagation model, coupled with the flow and geomechanical computations, is implemented in the MATLAB Reservoir Simulation Toolbox (MRST). The flow and geomechanical calculations are discretized by the finite volume and the virtual element methods, respectively. The hydraulic fracture is set to propagate along a prescribed path with a specific propagation or activation criterion. The accuracy of our model is validated against the KGD analytical solutions for the leak-off-viscosity, storage-viscosity and leak-off-toughness dominated regimes. The simulated stress and strain features are consistent with those interpreted from field LF-DAS signals. Several case studies and sensitivity analyses demonstrate the approach's utility and examine fracture interference, closure, and stress shadowing effects. The modelling work facilitates interpreting field measurement data by investigating characteristics of fracture hits from adjacent wells. The modelling method provides insights into fracture interference and its implications on optimal designs during hydraulic fracturing stimulation.

Effects of fluid composition and salinity on subcritical crack growth in granite

Using the double-torsion technique, the fracture mechanical response of granite specimens was investigated under the influence of fluid with different electrolyte types and salinities. The fracture toughness (KIC) and critical mechanical energy release rate (G0) of the granite in electrolyte solution are weakened compared to those in distilled water. The KIC in all electrolyte solutions is 2.08–2.28 MPa·m1/2, which is 8.4 % − 16.5 % lower than that in distilled water, and it is insensitive to ion type and salinity. In contrast, the subcritical crack growth index (n) shows different salinity dependence in three salt (AlCl3, CaCl2, and NaCl) solutions. The slight increase in n with rising salinity of the AlCl3 solution is attributed to crack tip blunting caused by over-dissolution of minerals. The n and G0 decrease and then increase with rising salinity of CaCl2 solution, which may be related to the salinity-dependent dissolution rate of quartz and the weakening of repulsive force between crack surfaces. The n and G0 shows a negative correlation with salinity and decrease by 26.4 % and 15.4 %, respectively as the NaCl salinity increases from 0.1 M to 1.0 M. Limitations in the dissolution reactions of the main minerals (albite, biotite and diopside) is accountable for enhancement of n in silica solutions. Experimental results emphasize the critical and subcritical fracture behavior of the granite in response to chemically reactive fluids with implications for both hydraulic fracture stimulations in geothermal fields and caprock integrity for CO2 sequestration. In these applications, the fracture properties of the reservoir rock can be enhanced or weakened by changing the electrolyte type and salinity of the fluid, depending on the actual requirements.

Monitoring spatiotemporal evolution of fractures during hydraulic stimulations at the first EGS collab testbed using anisotropic elastic-waveform inversion

The EGS Collab project acquired continuous active-source seismic monitoring (CASSM) data before, during, and after hydraulic stimulations at the first testbed at the depth of 4850 ft (1478 m) at the Sanford Underground Research Facility in Lead, South Dakota, for monitoring fracture creation and evolution. CASSM acquisition was conducted using 24 hydrophones, 18 accelerometers, and 17 piezoelectric sources within four fracture-parallel wells and two orthogonal wells. 3D anisotropic traveltime tomography and anisotropic elastic-waveform inversion of the campaign cross-borehole seismic data show that the rock within the stimulation region is a heterogeneous horizontal transverse isotropic medium. We use these inversion results as the initial models and apply 3D anisotropic first-arrival traveltime tomography and 3D anisotropic elastic-waveform inversion to the CASSM data acquired after each stimulation in May, 2018 and December, 2018. We observe the spatiotemporal evolution of seismic velocities and anisotropic parameters caused by hydraulic fracture stimulations, showing the regions of rock alternation caused by hydraulic fracture stimulation.

A Systematical Review of the Largest Alkali-Surfactant-Polymer Flood Project in the World: From Laboratory to Pilots and Field Application

Summary This paper presents a systematical review of the largest alkali-surfactant-polymer (ASP) flood project in the world, applied to the largest oil field in China. First, reservoir and fluid characteristics are highlighted. Next, project history is summarized, including laboratory studies, pilot tests, industrial-scale tests, and fieldwide application. Third, typical ASP flooding performance and reservoir management measures from more than 30 years’ experience are presented. In addition, performances of ASP flood and polymer flood in the same field, which is also the largest project in the world, are compared. The Lamadian-Saertu-Xingshugang (La-Sa-Xing) Field in the Daqing Field Complex (including the La-Sa-Xing Field and three smaller satellite fields) is the largest oil field in China. The Upper Cretaceous Saertu-Putaohua-Gaotaizi reservoir has an average porosity of 25% and average permeability of 610 md. The reservoir consists of more than 100 flow units with an average gross and net thickness of 1,377 ft and 394 ft, respectively, and is characterized by significant heterogeneity, both vertically and laterally. The reservoir lies at a depth of 2,566–2,585 ft true vertical depth (TVD), with original reservoir pressure of 1,534–1,740 psi and a reservoir temperature of 113–122°F. Crude oil has an API gravity of 33° and a viscosity of 9 cp at reservoir conditions. The discussed ASP flood project mainly targets high-quality reservoir sands. The field was brought on-stream in 1960 with immediate waterflood. Crossflow and water breakthrough became common issues during water injection, calling for a suitable enhanced oil recovery (EOR) method. The Saertu-Putaohua-Gaotaizi reservoir features favorable conditions for ASP flood, such as temperature, viscosity, permeability, and formation water salinity (7000 mg/L). In addition, the heterogeneous reservoir (permeability variation coefficient of 0.6–0.8) is suitable for ASP flood. ASP flood was studied in the laboratory from 1987 to 1993, followed by five small-scale pilots from 1994 to 1999, all being successful with incremental recoveries of ~20% stock tank oil initially in place (STOIIP). As a result, industrial-scale tests were conducted from 2000 to 2007, resulting in substantial improvement in production from ~4,000 BOPD to greater than 19,000 BOPD. Encouraged by those successes, the ASP project was expanded to fieldwide since December 2007, which is the largest ASP flood project in the industry worldwide. By 2021, daily oil production by ASP flood had reached 96,000 BOPD through 4,825 producers and 4,825 injectors. The actual average incremental recovery factor is 20% over waterflood and 8–10% over polymer flood, resulting in ultimate recovery factor of >60%. Zonal injection and profile modification are effective measures to further improve sweeping efficiency. Scaling is the major challenge during the operation of ASP flood, which is mitigated or remediated by adopting weak alkali ASP, progressive cavity pumps (PCP), scale inhibitor treatment, and fracturing stimulation on damaged wells. As of 2022, oil production by ASP flood is still ongoing at 88,635 BOPD, accounting for 39.9% of total field production. The world’s largest ASP flood project in the La-Sa-Xing Field proved the fieldwide applicability of ASP flood, both technically and economically. The effective reservoir management measures and lessons learned from more than 30 years’ experience provide valuable experiences for large-scale ASP flood projects in the industry.

A Grand Challenge: Update on Improved Recovery From Tight/Shale Reservoirs

_ This is the third of a series of six articles on SPE’s Grand Challenges in Energy, formulated as the output of a 2023 workshop held by the SPE Research and Development Technical Section in Austin, Texas. Described in a JPT article last year, each of the challenges will be discussed separately in this series: geothermal energy; net-zero operations; improving recovery from tight/shale resources; carbon capture, storage, and utilization; digital transformation; and education and advocacy. _ The exploration and extraction of hydrocarbons from tight or shale formations have revolutionized the global energy landscape, unlocking vast oil and gas reserves previously considered inaccessible. According to estimates, substantial oil production has been reported for various tight plays in the US in 2024 (Fig. 1). However, the production process in tight or shale formations is not without its own set of challenges ranging from technological hurdles to environmental concerns. Therefore, understanding the current outlook is essential for stakeholders to navigate the complex terrain. To address the significant issues outlined by SPE in July 2023 (Halsey et al. 2023), this article intends to explore the complexities of hydrocarbon extraction from tight and shale reservoirs. Description of Tight/Shale Formations First, we present a succinct description of tight or shale formations. Tight or shale oil and gas are hydrocarbons found in oil-bearing mudstone, and shale gas is produced from gas shale or associated with tight oil (Boak and Kleinberg 2020). Tight unconventional formations are characterized by the presence of fine-grained sedimentary rocks that are high in organic matter, such as shale, where hydrocarbons are firmly embedded within the rock matrix. Challenges in Tight or Shale Oil Production The Existence of Complex Geometry. Tight and shale formations are known for their complex geological structures, which can make it difficult to predict the distribution and behavior of hydrocarbons within the reservoir. Additionally, shale formations can exhibit significant variability in their thickness, composition, and the occurrence of natural fractures. Hence, it is crucial to understand and navigate the intricate geology of unconventional shale formations to achieve successful shale oil production (Jiang et al. 2016). Ultralow Reservoir Permeability. The low permeability of tight formations restricts the flow of hydrocarbons, necessitating techniques such as hydraulic fracturing to create artificial pathways for extraction. However, the effective stimulation of fractures requires the use of cutting-edge drilling and extraction methods, such as multistage hydraulic fracturing (fracking) and horizontal drilling, which in turn require precise engineering and a thorough understanding of reservoir characteristics (Pokalai et al. 2015).

Fracture Stimulation Increases Production in Challenging North African Completions

Fracture Stimulation Increases Production in Challenging North African Completions

Interpretasi Rekahan Hydraulic Fracturing dengan Menggunakan Permodelan Simulator Fraccade Berdasarkan hasil Rock Properties Pada Sumur X Lapangan Y

Interpretation Fractures of Hydraulic fracturing with Fraccade Model Based on Rock Properties Results at Well X Field Y.Identifying fractures based on the results of Rock Properties purpose is to find out and get results during the identification process from the results of Hydraulic fracturing stimulation with the purpose of getting a conclusionwhether or not the operation is successful. Well X has several problems such as high skin and low permeability, because of that Hydraulic fracturing stimulation is the most effective action for this well.The method used is to select data data and the condition of well X to visualize the data results from Fraccade software V 5.4.1. And do calculations using Ms. Excel. The parameters that calculated in this Final Project include rock geometry, rock permeability, and wellbore damage. After identifying and interpreting the data using Fraccade V 5.4.1 software. The results show that not much different between manual calculation and Fraccade software.

Strain energy dependent numerical simulation of rock fracture initiation and propagation using soundless cracking demolition agents (SCDA): Effects of SCDA-filled rock joints

Soundless Cracking Demolition Agents (SCDA) are gaining traction as an innovative technique for controlled rock fracturing in applications such as underground energy, mineral extraction, and excavation. This paper presents a novel numerical approach to simulate SCDA-charged rock fracture initiation using the strain energy density of SCDA. This approach eliminates the need for prior knowledge of the peak expansive pressure developed in a rock, a common requirement in conventional SCDA modelling. An empirically derived model is presented which captures the rate of energy release in SCDA as a function of applied strain to the surrounding material. The model was implemented in the 3-dimensional Distinct Element Code by applying an exponential strain-rate decay function. The proposed fracture stimulation method accurately mimics the expansion behaviour and finite strain energy release from SCDA expansion. The method was extended to simulate SCDA expansion in rock joints. The SCDA expansion method was assessed by creating a numerical model in which a central injection well was intersected by a horizontal joint and SCDA expansion was simulated in the injection well and the joint. The simulations were verified against laboratory fracture experiments. The model was extended to evaluate the fracturing performance of SCDA under varying joint roughness and confining pressures. SCDA expansion in rock joints introduces an additional compressive stress field that inhibits fracture initiation and propagation near the joint. Increasing fracture roughness suppressed fracture growth, but led to more fracture nucleation points around the injection well and shear damage at the joint interface. The simulation method employed shows sensitivity to confining pressures and simulates the fracturing potential of SCDA in different rocks subjected to confining pressures without requiring further calibration of the SCDA expansion parameters. The proposed numerical simulation method improves the accuracy in investigating the fracturing potential of expansive agents over existing simulation methods for SCDA.

Simulation and optimization of unstable dynamic propagation of multiple fractures in the shale formation

Multi-cluster hydraulic fracturing of horizontal wells is a well-adopted technique with high efficiency to increase the production of tight and shale formations. However, the stress shadows among clusters pose challenges to the synchronous propagation of hydraulic fractures during multi-cluster fracturing. In order to explore the fracture propagation mechanism and characteristics under the influence of stress shadow in low-spacing staged multi-cluster fracturing, a three-dimensional hydraulic fracturing model was generated using a lattice-based method. This model considered the impact of geological and engineering parameters on the propagation behavior of multiple fractures in shale formation. A variable pumping approach is adopted, where the fracturing fluid is initially injected at a high rate and then transitioned to a lower rate. Afterward, a method was proposed to quantitatively assess the extent of fracturing in a specific area (i.e., the stimulated area), considering the impact of stress shadow within a single stage. The simulation results demonstrated significant differences in the fracture stimulation area due to the influence of each parameter in the case of uncontrollable geological factors and controllable engineering factors. An increase in both Young’s modulus and stress anisotropy of the reservoir results led to a corresponding increase in the total fracture stimulation area. As the principal stress orientation increased, the fracture stimulation area gradually decreased. In terms of operational parameters, the stimulated area of hydraulic fractures gradually decreased as the fracture spacing increased. With increasing injection rate, the stimulated area initially expanded and then decreased, peaking at an injection rate of 0.04 m3/s. These findings can provide valuable insights into the propagation behavior of multi-cluster hydraulic fractures under uncertain parameters, with significant implications for future engineering applications.

Shale oil development techniques and application based on ternary-element storage and flow concept in Jiyang Depression, Bohai Bay Basin, East China

The ternary-element storage and flow concept for shale oil reservoirs in Jiyang Depression of Bohai Bay Basin, East China, was proposed based on the data of more than 10 000 m cores and the production of more than 60 horizontal wells. The synergy of three elements (storage, fracture and pressure) contributes to the enrichment and high production of shale oil in Jiyang Depression. The storage element controls the enrichment of shale oil; specifically, the presence of inorganic pores and fractures, as well as laminae of lime-mud rocks, in the saline lake basin, is conducive to the storage of shale oil, and the high hydrocarbon generating capacity and free hydrocarbon content are the material basis for high production. The fracture element controls the shale oil flow; specifically, natural fractures act as flow channels for shale oil to migrate and accumulate, and induced fractures communicate natural fractures to form complex fracture network, which is fundamental to high production. The pressure element controls the high and stable production of shale oil; specifically, the high formation pressure provides the drive force for the migration and accumulation of hydrocarbons, and fracturing stimulation significantly increases the elastic energy of rock and fluid, improves the imbibition replacement of oil in the pores/fractures, and reduces the stress sensitivity, guaranteeing the stable production of shale oil for a long time. Based on the ternary-element storage and flow concept, a 3D development technology was formed, with the core techniques of 3D well pattern optimization, 3D balanced fracturing, and full-cycle optimization of adjustment and control. This technology effectively guides the production and provides a support to the large-scale beneficial development of shale oil in Jiyang Depression.

Guest Editorial: Are We “Refracturing” or “Recompleting” with Mechanically Isolated Subsequent Stimulations in Organic Shales?

Numerous articles and technical papers have shown that perforating and fracture stimulating previously undrained rock in wide-cluster-spaced legacy organic shale wellbores can result in superior economics to new wells in many areas. With advances in mechanical isolation operators can seal off the narrow existing drainage intervals in legacy wells to enable stimulations to focus on “new rock.” In one reservoir-pressure-monitoring pilot well drilled by ConocoPhillips in 2016 it was observed that 85% of the lateral interval was not being drained where the original completion had 50-ft cluster spacing. The observation well was 70 ft away from the producing parent well. For wells that have relatively wide well spacings (over 600 ft), the post-stimulation total enhanced ultimate recovery (EUR) can be from three to four times the original EUR. The two most active operators doing these types of stimulations in the Eagle Ford Shale (ConocoPhillips and Devon) are primarily doing protective treatments in parent wells to avoid significant child well EUR losses from asymmetric fractures. In URTeC 3724057, Barba et al. demonstrated that when parent wells are restimulated following mechanical isolation the combined NPV10 of the post-stimulation production from the parent and the EUR preservation from the children is significantly higher than a new well’s NPV10. The first-order child wells will have asymmetric fracs running home toward the parents and stranding 40% of the reserves on their distal side if a protective refrac is not done on the parent, as was shown in SPE 213075. The second-order child wells have an average of a 20% EUR loss. Discussions with operators and presentations by upper management concerning this damage indicate that other than a few of the main players doing these subsequent stimulations, not all operators are aware of the detrimental effects of asymmetric fractures. A major operator presenting at the 2023 SUPER DUG Conference mentioned that they saw positive production increases when Bakken parent wells had fracture-driven interactions (FDIs) from offset child-well fracs. When the author asked the presenter in the Q&A session if they were concerned about the EUR damage from the asymmetric fractures which resulted in these FDIs, he was clearly not aware that it was a problem. For those who might not fully grasp the nuances of challenging parent-child interactions, consider the situation of parents supporting adult children who have not yet achieved independence. The goal for these parents is to encourage self-reliance and maturity, rather than a return to a dependent lifestyle. In the context of well management, the parent-well protective refrac is also designed to enable child wells to achieve their maximum production potential. While these protective recompletions in legacy parent wells can provide a significant economic benefit, the treatments have not been accepted by all operators as a tool to significantly grow company asset value. There is little or no activity in areas where all the wells on a pad are legacy parent wells with no nearby children.

Seismic monitoring of EGS fracture stimulations at Utah FORGE (Part 1): Time-lapse variations of b-values and Shear-wave Splitting Rates of induced microearthquakes

Characterizing geologic formations near geothermal wells is crucial for efficient extraction of subsurface geothermal energy resources. To monitor effective fracture stimulation of enhanced geothermal systems (EGS), we analyze a catalog of induced microearthquakes to characterize seismicity induced by Phase 2C fracture stimulations of the Utah FORGE project and derive the b-values for 424 induced microearthquakes in three stages of fracture stimulation. We find the time-lapse variations of these b-values. We apply eigenvector rotation and waveform correlation to 3C geophone data to separate fast S1 and slow S2 waves, determine their directions, measure their lag time, and calculate the S-wave splitting rate (SSR) for six induced microearthquakes in Stage 1 and 21 in Stage 3. Both SSR values and b-values increase with time. The increase in these values may be related to heavily fractured zones created by fracture stimulations during Stage 2 injections. Large and highly variable SSR values in Stage 3 may reflect heterogeneities in the fracture zones. Time-lapse variations of SSR values and b-values may be one of the most useful approaches to monitoring and characterizing the effectiveness and efficiency of various types of fracture stimulations.

Source mechanism of kHz microseismic events recorded in multiple boreholes at the first EGS Collab testbed

Continuous microseismic monitoring using three-component (3C) accelerometers deployed in multiple boreholes allows for tracking the detailed evaluation of mesoscale (∼10 m scale) fracture growth during the fracture stimulation experiments at the first Enhanced Geothermal Systems (EGS) Collab testbed. Building on a well-constrained microseismic event catalog, we invert for moment tensor of the events to better understand the fracture geometry and stress orientations. However, it is challenging because of the unknown orientation of 3C accelerometers and low signal-to-noise-ratio nature of high-frequency (several kHz) monitoring. To address these challenges, we first perform the hodogram analysis on the continuous active-source seismic monitoring (CASSM) data to determine the orientations of the 18 3C accelerometers. We then apply the principal component analysis (PCA) to the observed microseismic waveforms to improve the signal-to-noise ratios. We perform a grid search for the full moment tensor by fitting the PCA-denoised waveforms at a frequency range of 5 to 8 kHz. The moment tensor results show both the creation of hydraulic fractures and the reactivation of natural fractures during the hydraulic stimulations. Our stress inversion based on the inverted moment tensors reveals the alteration of stress regime caused by hydraulic fracture stimulations.