Hydraulic Fracture Stimulation Research Articles

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.

Transparent gelatin as a reservoir analogue: Dimensional scaling for hydraulic fracturing laboratory experiments

Gelatin is frequently used as a reservoir analogue for modeling hydraulic fracture (HF) growth in brittle, organic-rich rocks; its transparency enabling direct, visual observation of the HF growth. However, not many works have assessed the scalability of laboratory experiments on gelatin blocks with-respect-to “real-world” HF stimulation treatments. In this work, lab-scale parameters are compared against typical slickwater and crosslinked-gel stimulation treatment parameters from the Barnett Shale in northeastern Texas, for comprehensive (geometric, kinematic, and dynamic) dimensional-scaling evaluations.Dimensionless groups relating lab-scale physical models that display HF growth to the field-scale parameters are used to quantify the representation of elastic deformation, crack formation energy, treatment time-duration, and stress confinement, honoring the governing principles for fluid-driven fracture propagation in linearly-elastic media (applicable to HF growth in rocks, as well as magmatic intrusions, such as dykes or sills). The analysis demonstrates gelatin as a reservoir analogue to exhibit enhanced scaling against crosslinked gel compared to slickwater stimulation treatments, with the laboratory conditions accentuating toughness over viscous effects in comparison to field conditions, something which if neglected can lead to biased conclusions. Henceforth, a set of laboratory parameters is proposed for gelatin blocks of a practically-attainable powder concentration that yields improved scalability against the prototype parameters, minimizing the discrepancy between the lab-scale and the corresponding field-scale values for each dimensionless group, inside the limits of standard laboratory equipment.Identical dimensional-scaling evaluations are performed on lab-scale parameters from past experimental studies reported in the literature where gelatin samples were used, to the extent that the published data allows, indicating poor scaling of the physical phenomena. Results and conclusions from such inadequately-scaled experiments should be treated with suspicion.

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.

Stress‐induced anisotropy in Gulf of Mexico sandstones and the prediction of in situ stress

AbstractThe strong sensitivity of velocity to stress observed in many sandstones originates from the response of stress‐sensitive discontinuities such as grain contacts and microcracks to a change in effective stress. If the change in stress is anisotropic, then the change in elastic wave velocities will also be anisotropic. Characterization of stress‐induced elastic anisotropy in sandstones may enable estimation of the in situ three dimensional stress tensor with important application in solving problems occurring during drilling, such as borehole instability, and during production, such as sanding and reservoir compaction. Other applications include designing hydraulic fracture stimulations and quantifying production‐induced stresses which may lead to rock failure. Current methods for estimating stress anisotropy from acoustic anisotropy rely on third‐order elasticity, which ignores rock microstructure and gives elastic moduli that vary linearly with strain. Elastic stiffnesses in sandstones vary non‐linearly with stress. Using P‐ and S‐wave velocities measured on Gulf of Mexico sandstones, this non‐linearity is found to be consistent with a micromechanical model in which the discontinuities are represented by stress‐dependent normal and shear compliances. Stress‐induced anisotropy increases with increasing stress anisotropy at small stress but then decreases at larger stresses as the discontinuities close and their compliance decreases. When the ratio of normal‐to‐shear compliance of the discontinuities is unity, the stress‐induced anisotropy is elliptical, but for values different from unity, the stress‐induced anisotropy becomes anelliptic. Although vertical stress can be obtained by integrating the formation's bulk density from the surface to the depth of interest, and minimum horizontal stress can be estimated using leak‐off tests or hydraulic fracture data, maximum horizontal stress is more difficult to estimate. Maximum horizontal stress is overpredicted based on third‐order elasticity using measured shear moduli, with estimates of pore pressure, vertical stress and minimum horizontal stress as input. The non‐linear response of grain contacts and microcracks to stress must be considered to improve such estimates.

Detecting fractures and monitoring hydraulic fracturing processes at the first EGS Collab testbed using borehole DAS ambient noise

Enhanced geothermal systems (EGS) require cost-effective monitoring of fracture networks. We validate the capability of using borehole distributed acoustic sensing (DAS) ambient noise for fracture monitoring using core photos and core logs. The EGS Collab project has conducted 10 m scale field experiments of hydraulic fracture stimulation using 50–60 m deep experimental wells at the Sanford Underground Research Facility (SURF) in Lead, South Dakota. The first EGS Collab testbed is located at 1616.67 m (4850 ft) depth at SURF and consists of one injection well, one production well, and six monitoring wells. All wells are drilled subhorizontally from an access tunnel called a drift. The project uses a single continuous fiber-optic cable installed sequentially in the six monitoring wells to record DAS data for monitoring hydraulic fracturing during stimulation. We analyze 60 s time records of the borehole DAS ambient noise data and compute the noise root-mean-square (rms) amplitude on each channel (points along the fiber cable) to obtain DAS ambient noise rms amplitude depth profiles along the monitoring wellbore. Our noise rms amplitude profiles indicate amplitude peaks at distinct depths. We compare the DAS noise rms amplitude profiles with borehole core photos and core logs and find that the DAS noise rms amplitude peaks correspond to the locations of fractures or lithologic changes indicated in the core photos or core logs. We then compute the hourly DAS noise rms amplitude profiles in two monitoring wells during three stimulation cycles in 72 h and find that the DAS noise rms amplitude profiles vary with time, indicating the fracture opening/growth or closing during the hydraulic stimulation. Our results demonstrate that borehole DAS passive ambient noise can be used to detect fractures and monitor fracturing processes in EGS reservoirs.

Controls on mechanical properties of a carbonate mudstone: Insights from non-destructive techniques and geochemical data

This study quantifies geomechanical properties of carbonate mudrocks in the Arabian intra-shelf basin, focusing on different sedimentologic zones (proximal to distal). Core-based mechanical properties were obtained through unconfined conditions. Micro Rebound Testing (MRT) was conducted on 700′ ft of core at 0.5 ft intervals to capture high-resolution rock hardness (HLD), unconfined compressive strength (UCS), and static Young's Modulus (E). Additional tests validated log-based parameters, including impulse hammer, acoustic velocity testing for (E), P-wave and S-wave velocities (Vp and Vs), scratch testing, and XRF/XRD analyses for mineralogical and elemental variability impact on mechanical properties.Multivariate statistical analysis correlates mechanical properties with elemental data, showing direct proportionality to calcium percentage, (E), Vp, and Vs, while inversely correlated to aluminum, iron, sulfur, and total organic carbon (TOC), especially in distal zones. Porosity, as measured by neutron porosity log, is a significant control on mechanical properties, with higher porosity resulting in lower mechanical properties at any given calcium percentage. Variations in geomechanical properties within each zone are principally controlled by depositional environments, sediment supply, diagenesis, and a pycnocline dividing the water column into anoxic, dysoxic (or suboxic), and oxic conditions.Zone 1A and 4 exhibit high brittleness characterized by high Ca-calcite, HLD, (E), Vp, Vs., low terrigenous elements/minerals, and porosity. Zone 1B and 2A are moderately brittle, showing a slight decrease in brittleness and a slight increase in terrigenous elements/minerals, porosity, and organic matter, particularly in the distal zone (Zone 1B). Zone 2B, 3A, and 3B represent moderate to highly ductile zones with low levels of Ca-calcite, HLD, (E), Vp, Vs, and an increase in terrigenous elements/minerals, porosity, and TOC, especially in the distal zone (Zone 2B and 3B). This study highlights the value of high-resolution mechanical data from cores with applications for improved stress estimation and hydraulic fracture stimulation in unconventional reservoirs.

Fracture size inversion method based on water hammer signal for shale reservoir

Hydraulic fracturs size inversion plays an important role on evaluating hydraulic fracturing efficiency. Fracture size can be calculated by microseism events or all the pressure data generated by hydraulic fracturing stimulations. These methods are time-consuming. However, the sudden shutoff of pumping can induce a special data known as the water hammer signal. The size of this data is much fewer than others so using it to calculate fracture size is efficient. This study proposes a method of using water hammer signal to work out the hydraulic fracture size. The numerical simulation model is proposed based on the transient flow model to describe the water hammer behavior. The impacts of fracture on water hammer behavior are represented by three parameters (R,C and I). Through these parameters, the fracture size can be calculated. The accuracy of this method is validated by comparing fracture size inversion results between different methods. The results show that the parameter C and R have obvious impacts on water hammer signal and they can cause the amplitude of water hammer signal alternate from 5 to 2 MPa. In addition, this method is accurate for fracture size calculation and the overall error between its results and ones from normal methods is about 6.28%. This method is more suitable for fractures away from horizontal well toe than ones near to well toe. The mean error of fractures away from well toe is only 3.49% but it is 12.75% for fracture near well toe. It is because that the fracture structure is complex near well toe. It indicates that the more accurate relationship between fracture size and parameters (R,C and I) is required for fracture with complex structure.

Effects of Drilling Number and Distribution on Fracture Using the Pulse Plasma on Tight Sand Reservoir

Summary The permeability of unconventional reservoirs is extremely low, resulting in their drainage area being limited to tens of feet. Therefore, researchers have developed an effective stimulation technology that can be used in combination with conventional hydraulic fracturing, namely, pulsed plasma fracturing technology. Pulsed plasma fracturing technology is an efficient and environmentally friendly auxiliary hydraulic fracturing stimulation technology. However, most existing studies have focused only on the effect of pulsed plasma fracturing on single wells, ignoring the effect of the number and distribution of wells drilled on pulsed plasma fracturing. In this paper, pulsed plasma fracturing is studied by a self-built pulsed plasma experimental platform and nonlinear finite element software. First, the generation and propagation mechanism of shock wave, fracture type, and stress field analysis of rock mass in pulsed plasma fracturing technology are discussed. The double-well experiment was carried out by using the experimental platform, and the fracture law of fractures under different wellhead distribution conditions was obtained. In addition, a multiwell mathematical model is established by using the combination of the Euler method and Lagrange method to simulate the interaction between fluid and solid, that is, arbitrary Lagrangian Eulerian (ALE) multimaterial fluid-solid coupling method and the influence of drilling times and wellhead distribution on pulsed plasma fracturing is discussed. Stress analysis shows that the rock is mainly affected by ground stress, liquid column pressure, and shock wave pressure. The experimental results show that the discharge voltage is positively correlated with the shock wave pressure on the rock. The distribution of different wellheads affects the distribution and length of fractures. The double-well experiment makes the fractures easier to fracture. The simulation results show that the fracture length in the connection direction of the two wells is longer, and the fracture length in the vertical direction is shorter. This shows that the number and distribution of drilling affect the initiation and propagation of fractures.

Improving oil and gas flowability in tight carbonates with a novel solid delayed acid

The economic development of tight carbonate reservoirs requires hydraulic or acid fracturing stimulation. Acid fracturing better activates natural fractures, resulting in increased stimulated reservoir volume and improving oil and gas flowability. In order to solve the problem of excessive acid-rock reaction due to high temperature, this paper screened four kinds of solid forms of acid with the maximum quantity of acid and reaction rate as the index and formed a high temperature-resistant mixed solid acid system with solid organic acid as the main part and inorganic solid acid as the auxiliary part. The maximum quantity of acid produced and effective acid concentration of the system were greater than 50%, and no residue was precipitated after the complete reaction. Dynamic acid-rock rate tests were performed on different types of retarded acid at 140 °C. The test results show that the solid acid dissolves to form a low-viscosity acid solution, and the reaction rate is one order of magnitude lower than that of gelled and cross-linked acids at the same hydrogen ion concentration, and it is little affected by temperature. Moreover, the paper compares the treatment effect of micro-proppants and solid acids on micro-fractures. The results show that the core permeability improvement multiples up to 900 times under low dissolution of solid acid and the formation of oil and gas flow channels with the same scale as micro-proppants. The experimental results demonstrated the ability of solid delayed acid to transport the fracture leading edge at high temperatures and effectively activate micro-fractures.

Investigation of enhanced geothermal system in the Basal Cambrian Sandstone Unit, Alberta, Canada

Given the climate challenge, society is seeking low greenhouse gas emission energy sources. In jurisdictions such as Alberta, Canada where power is largely generated through the combustion of natural gas, geothermal offers a compelling option but it remains unclear as to its economic and technical viability. Here, we examine the potential for an enhanced geothermal system in the Basal Cambrian Sandstone Unit in Alberta, Canada. Prior to geothermal operation, hydraulic fracturing is conducted to enhance the permeability of the thermal reservoir. This lowers the pressure drop required for circulating fluids through the system. The results show that the open-loop enhanced geothermal system realizes an energy produced to energy invested ratio from 4 to 9 depending on different operating rate. The results also suggest that applying hydraulic fracturing can accelerate energy harvesting and energy efficiency over the early stages of the process but the greater the injection rate, the smaller is this benefit of hydraulic fracturing stimulation.

Comparative Experimental Study of Fracture Conductivity of Carbonate Rocks under Different Stimulation Types.

Carbonates have great potential for development, but the use of propped hydraulic fracturing or acid fracturing stimulation types alone has limited effectiveness. This study collected four sets of rock samples from three carbonate reservoirs: dolomite, limy dolomite, and limestone. The laboratory analysis focuses on propped hydraulic fracturing, acid fracturing, and acid fracturing plus proppants of these rock types. The aim is to assess acid erosion, proppant embedment depth, and the impact of varying proppant sizes and acid injection on fracture conductivity. The results showed that acid fracturing substantially enhanced the hydraulic conductivity of the three rocks. The embedded depth of the small-sized proppant was greater, but the fracture conductivity of the large-sized proppant was greater. Under the conditions of the actual pressure of formation of 55.2 MPa in the target reservoir, using 70/140 mesh proppant, 20% thickened acid, and an injection rate of 20 mL/min: for the dolomite-type rock, the propped hydraulic fracturing method had the highest fracture conductivity, which reached 151.17 D·cm. For the limy dolomite-type rock, the acid fracturing plus proppant experiment had the highest fracture conductivity, which was 157.26 D·cm. For limestone-type rocks, acid fracturing had the highest fracture conductivity of 210.39 D·cm. This study helps to elucidate the mechanism of different stimulation types and provides useful guidance for the more effective development of carbonate oil and gas reservoirs.

Combined Effect of In Situ Stress Level and Bedding Anisotropy on Hydraulic Fracture Vertical Growth in Deep Marine Shale Revealed via CT Scans and Acoustic Emission

The economic exploitation of unconventional gas and oil in deep shale relies closely on effective hydraulic fracturing stimulations. However, the fracturing operations of deep shale reservoirs face challenges of insufficient fracture growth and a rapid decline in productivity due to the increasing in situ stress level. In addition, the shale strata on the margin of the Sichuan Basin are frequently folded and faulted, and the change in bedding inclinations significantly complicates the process of hydraulic fracturing. The investigation of the combined effect of the in situ stress level and bedding anisotropy on the hydraulic fracture configuration is vital for fracturing engineering design. To analyze this, we conducted hydraulic fracturing tests on shale cores to simulate the hydraulic fracture initiation and growth from a horizontally positioned perforation. By using acoustic emission detection and CT scans, the influence of natural stress levels and the angle of the shale’s bedding on the process of hydraulic fracturing in shale and the resulting fracture geometry were analyzed. The results showed that the area of hydraulic fracture under a higher stress level (σ1 = 50 MPa, σ3 = 40 MPa) was about 13%~23% smaller than that created under the lower stress level (σ1 = 30 MPa, σ3 = 20 MPa) when the bedding angle was smaller than 60°. With the increase in bedding angle, the curves of the fracture area and fracture network index under two different stress levels presented similar decreasing trends. Also, the time from micro-crack generation to sample breakdown was significantly reduced when the bedding orientation changed from the horizontal to vertical position. The increasing stress level significantly increased the breakdown pressure. In particular, the fracturing of shale samples with bedding angles of 0° and 30° required a higher fluid pressure and released more energy than samples with larger bedding inclinations. Additionally, the measurement of the sample radial deformation indicated that the hydraulic fracture opening extent was reduced by about 46%~81% with the increasing stress level.

The Effect of Fracture Geometry on Proppant Size in Hydraulic Fracturing Design Optimization

Problems with sandstone reservoirs include the small initial permeability which will hinder fluid flow from the reservoir to the bottom of the well. This will cause a small initial productivity due to a small initial permeability so that it will be more difficult for oil to flow from the drain radius which causes a small Productivity Index value. The Hydraulic Fracturing stimulation method is applied to increase the permeability value by designing the fracture geometry, proppant size according to the fracture geometry, so that it is hoped that it can increase the permeability, transmissivity, production rate and productivity index. From the results of the research carried out, modeling results show that the success of hydraulic fracturing depends on the orientation of the fracture, the size and shape of the fracture, and rock properties such as permeability and strength. These results were proven by an increase in permeability which was previously only 2.3 mD after fracturing, increasing to 11.97 mD. The skin value which was previously 1.2 then improved to -6.31, which means the damage to the formation has been repaired. The productivity index, which was previously only 0.5 after fracturing, rose to 3.71. Lastly, the production rate also increased significantly from 28 Bopd neik to 129 Bopd. It can be said that the implementation of hydraulic fracturing in the AFG-01 Well was successful and effective in increasing production performance.

Experimental evaluation of the impact of induced fractures on cyclic solvent injection performance in low-permeability hydrocarbon reservoirs

Recovery factors associated with primary recovery (pressure depletion) schemes are often small (<5–10%) for low-permeability hydrocarbon reservoirs. As a result, cyclic solvent injection (CSI) schemes, using CO2 and produced gas, are currently being considered for enhanced hydrocarbon recovery (EOR). Fracture networks, generated during hydraulic fracturing stimulation, affect both primary and enhanced recovery by increasing the surface area contacted with the low-permeability reservoir matrix. However, experimental studies of the impact of induced (hydraulic) fractures on CSI performance are sparse, particularly those that provide a realistic representation of the fracturing process by inducing fractures under stress to better represent fracture conditions (e.g., fracture surface area, fracture surface roughness). Therefore, the primary objective of this work is to develop a laboratory-based workflow for evaluating the effectiveness of fracture system in tight oil reservoirs to enhance the oil recovery during a typical CSI cycle using a combination of core-scale techniques.An in-house core-flooding methodology, that combines ‘in situ’ fracturing and cyclic gas injection, was applied. The experimental procedure includes: 1) performing multiple cycles of lean gas (i.e., 80% C1 + 20% C2) injection into an oil-saturated ‘intact’ core plug until maximum oil recovery (5%) is reached, 2) artificially fracturing the core plug under stress, 3) repeating multiple cycles of lean gas injection into the artificially-fractured core plug, under similar experimental conditions as those used for the intact core, until maximum oil recovery (23%) is reached, and 4) measuring the fractured-core liquid permeability. A well-characterized tight siltstone core plug sample obtained from the Canadian Montney Formation was analyzed as an example. The experimental results indicate that 1) fracturing under stress results in an increase in surface area and permeability, and 2) the recovery factor is enhanced by ∼ 18% after fracturing (e.g., from ∼ 5% for intact core plug to ∼ 23% for artificially-fractured core plug).This study provides a proof-of-concept experimental approach for evaluating the impact of induced fractures on CSI recovery using an identical core plug sample (intact and fractured). The proposed experimental methodology could serve as a workflow for laboratory-scale evaluation of the impact of induced fractures on CSI performance in tight hydrocarbon reservoirs.

Multiscale pore structural alteration in gas shale by supercritical water stimulation

Hydraulic fracturing can induce high conductive fracture networks to stimulate shale gas well production. Large amounts of fracturing fluid generally retained in shale matrix after hydraulic fracturing will limit the shale gas well production. Reusing retained fracturing fluid by in-situ transformed into supercritical water (SCW) via formation heat treatment (FHT) is a state-of-the-art method to improve the shale gas well production by further altering shale multiscale pore structure. In this study, the changes in shale multiscale pore structure was visually and quantitatively characterized. The pore volume with a size range of 2 nm–5000 nm increased significantly. Inducing intragranular dissolution pores, pyrite dissolution pores, interparticle dissolution pores, and hydrothermal fractures stimulated the multiscale pore structure alteration during supercritical water stimulation (SCWS). Additionally, the advantage of SCWS in altering shale pore structure was systematically summarized, including further extend the hydraulic fracturing stimulation scale, enhancing multiscale shale gas flow capacity and ultimately improving well production. This work sheds light on the influence of supercritical water stimulation on the pore structure evolution in shale matrix, which is expected to be an innovative method for increasing the estimated ultimate recovery of a shale gas reservoir.

Comparative Study between Different Oil Production Enhancement Scenarios in an Iraqi Tight Oil Reservoir

This paper presents a comparative study between different oil production enhancement scenarios in the Saadi tight oil reservoir located in the Halfaya Iraqi oil field. The reservoir exhibits poor petrophysical characteristics, including medium pore size, low permeability (reaching zero in some areas), and high porosity of up to 25%. Previous stimulation techniques such as acid fracturing and matrix acidizing have yielded low oil production in this reservoir. Therefore, the feasibility of hydraulic fracturing stimulation and/or horizontal well drilling scenarios was assessed to increase the production rate. While horizontal drilling and hydraulic fracturing can improve well performance, they come with high costs, often accounting for up to 100% of the total well cost. To ensure economically viable flow rates and achieve maximum ultimate oil recovery, a technical and economic comparative study was conducted. The results indicate that hydraulic fracturing offers promising outcomes, with a total oil production of 153,816 Mbbl over 30 years from 25 fractured wells, resulting in a final Net Present Value (NPV) of 3,583.32 MM$. In contrast, the planned two horizontal wells exhibit lower eventual production and NPV compared to the majority of fractured wells. However, the 2000 m lateral section of well HF00Y-S00YH shows a slightly higher NPV. Considering the operational benefits and profitability, hydraulic fracturing should be seriously considered for the further development of the Saadi reservoir. This comparative study provides valuable insights into the most effective approach for enhancing oil production in tight reservoirs like Saadi, balancing the technical feasibility and economic viability of different stimulation scenarios. The findings can guide decision-making processes and contribute to maximizing oil recovery in similar challenging reservoirs.

Experiment and simulation of slurry flow in irregular channels to understand proppant transport in complex fractures

Slurry flow and proppant placement in irregular fractures are crucial to evaluate hydraulic fracturing stimulation but need to be better understood. This study aims to investigate how irregular fracture affects proppant transport and distribution using laboratory experiments and micro-scale numerical models. The unresolved method of the computational fluid dynamics (CFD) and the discrete element method (DEM) considers Saffman lift force, Magnus force, and virtual mass force to accurately capture the frequent interaction between proppant and slickwater. Experimental results validated the reliability of the optimized CFD-DEM model and calibrated primary parameters. The effects of crack height and width, bending angle, and distance between the crack and inlet on particle distribution were studied. The results indicated that the improved numerical method could rationally simulate proppant transport in fractures at a scale factor. The small crack height causes downward and upward flows, which wash proppant to the fracture rear and form isolated proppant dunes. A wider region in the fracture is beneficial to build up a large dune, and the high dune can hinder particle transport into the fracture rear. When the crack is close to the inlet, the primary fracture without proppants will close to hinder gas production. The smaller the bending angle, the smaller the proppant dune. A regression model can precisely predict the dune coverage ratio. The results fundamentally understand how complex fractures and natural cracks affect slurry flow and proppant distribution.

Hypocenter‐Based 3D Imaging of Active Faults: Method and Applications in the Southwestern Swiss Alps

AbstractDespite the fact that earthquake occurrence can be strongly influenced by the architecture of pre‐existing faults, it remains challenging to obtain information about the detailed subsurface geometries of active fault systems. Current geophysical methods for studying such systems often fail to resolve geometrical complexities at sufficiently high spatial resolutions. In this work, we present a novel method for imaging the detailed 3D architectures of seismically active faults based on high‐precision hypocenter catalogs, using nearest neighbor learning and principal component analysis. The proposed approach enables to assess variations in fault instabilities and kinematics. We apply the method to the relatively relocated St. Léonard (max.ML = 3.2) and Anzère (max.ML = 3.3) microearthquake sequences in the Southwestern Swiss Alps, revealing strike‐slip fault systems with interconnecting stepovers at depths of 3–7 km and lengths ranging from 0.5 to 2 km. In combination with additional information about fault instabilities and kinematics, we observe significantly reduced earthquake migration velocities and fault locking processes within the stepovers. Understanding such processes and their role in the propagation of strain across stepovers is of great relevance, as these structures can potentially limit earthquake ruptures but also represent possible locations for the nucleation of larger ruptures. Our proposed method is expected to be broadly useful for further applications such as monitoring hydraulic fracture stimulations or geothermal exploration of natural, fluid‐bearing faults. Conducting similar high‐resolution spatiotemporal analyses of microseismic sequences has the potential to greatly enhance our comprehension of how the 3D fault architecture impacts seismogenic fault reactivation.

Casing Leak Repair Allows Continued Hydraulic Fracturing

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212933, “Casing Leak Repair To Continue Hydraulic Fracture Stimulation,” by Gaston Oscar Ciminari, Gonzalo Cabo, SPE, and German Rimondi, Pluspetrol, et al. The paper has not been peer reviewed. _ The authors introduce a successful alternative for repairing casing failures on an unconventional well that allows hydraulic fracture continuity to accomplish the original fracturing plan, considering well-integrity conditions throughout the entirety of well production life as the main intervention objective. The resulting well production was higher than the expected estimated ultimate recovery (EUR) for the landing zone. Introduction In December 2020, during the execution of hydraulic fracturing on a three-well pad in the Vaca Muerta unconventional shale reservoir, an annular communication suddenly occurred in one of the wells. This event took place during the execution of the ninth fracturing stage of 33 planned. After a thorough pressure analysis of this event and verification that all pressure barriers were correct and in place, it was decided to stop fracturing treatments in this well and complete pending fracturing stages in the other two wells of the pad until the problem was well understood and a solution was found. Diagnostics The initial good condition of the well barrier was verified by a positive casing-integrity test (CIT) at 13,000 psi before the first fracturing pump. Maximum treatment pressure was kept under the CIT pressure, with an acceptable safety factor margin maintaining the well with annular communication, and was continuously pressure monitored. Once the fracturing fleet finished the intervention and left the pad, the engineering focus of the completion was oriented to determine the location and geometric characteristics of the casing leak. It was decided to start from the simplest to most-complex diagnostics interventions. The diagnostics interventions, and their results, are detailed in the complete paper. A bullheading pumping test was executed, and an increase in Section B pressure was observed. This showed clear communication between both sections. During circulation tests, it was observed that, by reducing pressure in Section B, Section A pressure response followed the pressure trend; opposite pressure changes in Section A, however, did not reflect on Section B pressure changes. Based on flow-test behavior, it was believed that a casing mechanical failure with a flow area of 0.044 in.2, equivalent to a 0.23-in. orifice, was the reason for the annular communication. With the aid of a coiled tubing (CT) unit and a bottomhole assembly (BHA) principally conformed with a multiple-set mechanical packer, it was possible to apply testing pressure below and above the packer seals at different depths to confirm the casing-leak position. A unique failure was located in the zone between 998 and 1002 m. A casing joint was located at 999.5 m; thus, it was assumed that a mechanical problem existed on this casing-joint connection. A wireline BHA composed of an injection-logging tool and a temperature sensor was used to reduce the zone of uncertainty. As a result of this log, the failure zone was located between 999.4 and 1000.4 m. The failure evidently was near the joint but not in it. Immediately after well-fluid changeout, the real-time downhole camera was run on wireline and showed what appeared to be a small hole 1 ft over the casing joint.

Economic and operational investigation of CO2 sequestration through enhanced oil recovery in unconventional reservoirs in Colorado, USA

The ongoing CCUS commercial projects are highly relied on the support of government incentives due to massive capital investment. This study analyzes the economics of carbon capture utilization and sequestration (CCUS) projects, shows a state-wide CCUS deployment exercise, followed by simulation results of enhanced oil recovery (EOR) based CO2 storage in unconventional reservoirs. The comprehensive economic analysis of capture, transportation, sequestration costs, enhanced 45Q tax credits, and EOR revenue implies the practicality of CO2-EOR to offset the high CCUS costs. With the economics understanding, we study the top CO2 sources, existing CO2 pipelines, and sequestration sinks in the state of Colorado, USA. This paper next presents results from EOR simulation in one section of the unconventional Denver-Julesburg (DJ) Basin Niobrara and Codell reservoirs. The simulation model is based on a geological static model, incorporated with hydraulic fracture stimulation, history matched to production, and calibrated to the microseismic and time-lapse surface seismic data. The CO2-EOR simulation results show that oil production can be increased and more CO2 stored with: a longer primary production period; the presence of a shut-in period; higher injection rates; and multi-well injectors. The modeling results show that about 7–10 Mscf of CO2 will be stored when recovering 1 stb of EOR oil. By adding the enhanced oil revenue and the carbon credits together, it is estimated that the most economic case can generate $13 MM when oil price is assumed to be $80/stb, and the EOR oil revenue is 3.4 times greater than that generated from 45Q incentives. It corresponds to the scenario that a five-year primary production is followed by CO2 injection into four wells with the sequence of injection (4 MMscf/day for 6 months), shut-in (6 months) and production (12 months). The best practices in this study will provide valuable insights for similar CCUS projects in other unconventional fields. Furthermore, this study defines a term named “Carbon Neutrality Index (CNI)” by comparing the amount of CO2 stored with that burned by EOR oil. The CNI value of 0 indicates the enhanced oil is carbon neutral; a negative CNI value implies there is a net reduction in carbon emission. The 4-year huff-n-puff (HnP) simulation leads to a positive CNI value, indicating that the EOR oil generated in this process is not carbon neutral yet.