scholarly journals An Experimental Study to Reduce the Fracture Pressure of High Strength Rocks Using a Novel Thermochemical Fracturing Approach

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-16 ◽  
Author(s):  
Zeeshan Tariq ◽  
Mohamed A. Mahmoud ◽  
A. Abdulraheem ◽  
Ayman Al-Nakhli ◽  
Mohammed BaTaweel
Keyword(s):  
Pressure Rise ◽  
High Strength ◽  
Hydrocarbon Reservoirs ◽  
Hydraulic Fractures ◽  
Breakdown Pressure ◽  
Fracture Pressure ◽  
Breakdown Time ◽  
Operational Window ◽  
Fracturing Experiments ◽  
Engineering Practices

Current oil prices and global financial situations underline the need for the best engineering practices to recover remaining oil from unconventional hydrocarbon reservoirs. These hydrocarbon reservoirs are mostly situated in deep and overpressured formations, with high rock strength and integrity. Breakdown pressure of the rock is a function of their tensile strength and in situ stresses acting on them. Fracturing stimulation techniques become challenging when treating these types of rocks, and many cases approached to the operational limits. This leaves a small operational window to initiate and place hydraulic fractures. In this study, a new methodology to reduce the breakdown pressure of the high stressed rock is presented. The new method enables the fracturing of high stressed rocks more economically and efficiently. Fracturing experiments were carried out on different blocks, and the breakdown pressure was measured by creating a simulated borehole at the center of the block. Thermochemical fluids were injected to create the microfractures. These microfractures improved the permeability and porosity and reduced the elastic strength of the subjected samples prior to the main hydraulic fracturing job. The posttreatment experimental analysis confirmed the presence of microfractures which were originated due to the pressure pulse generated from the thermochemical reaction. The results of this study showed that the newly formulated method of thermochemical fracturing reduced the breakdown pressure by 38% in slim borehole blocks and 60% in large borehole blocks. Results also showed that the breakdown time to initiate the fractures was reduced to 19% in slim borehole blocks and 17% in large borehole blocks. The reduction in breakdown pressure and breakdown time happened due to the creation of microfractures by the pressure rise phenomenon in a new thermochemical fracturing approach.

Chemically-Induced Pressure Pulse: Fracturing Competent Reservoirs

2021 ◽  
Author(s):  
Ayman R. Al-Nakhli ◽  
Zeeshan Tariq ◽  
Mohamed Mahmoud ◽  
Abdulazeez Abdulraheem
Keyword(s):  
Hydraulic Fracturing ◽  
Rock Fracture ◽  
Applied Pressure ◽  
Hydraulic Fractures ◽  
Breakdown Pressure ◽  
Hydrocarbon Production ◽  
Fracture Pressure ◽  
Micro Cracks ◽  
Chemically Induced ◽  
Fracturing Experiments

Abstract Commercial volumes of hydrocarbon production from tight unconventional reservoirs need massive hydraulic fracturing operations. Tight unconventional formations are typically located inside deep and over-pressured formations where the rock fracture pressure with slickwater becomes so high because of huge in situ stresses. Therefore, several lost potentials and failures were recorded because of high pumping pressure requirements and reservoir tightness. In this study, thermochemical fluids are introduced as a replacement for slickwater. These thermochemical fluids are capable of reducing the rock fracture pressure by generating micro-cracks and tiny fractures along with the main hydraulic fractures. Thermochemical upon reaction can generate heat and pressure simultaneously. In this study, several hydraulic fracturing experiments in the laboratory on different synthetic cement samples blocks were carried out. Cement blocks were made up of several combinations of cement and sand ratios to simulate real rock scenarios. Results showed that fracturing with thermochemical fluids can reduce the breakdown pressure of the cement blocks by 30%, while applied pressure was reduced up to 88%, when using thermochemical fluid, compared to slickwater. In basins with excessive tectonic stresses, the current invention can become an enabler to fracture and stimulate well stages which otherwise left untreated. A new methodology is developed to lower the breakdown pressure of such reservoirs, and enable fracturing. Keywords: Unconventional formation; breakdown pressure; thermochemicals; micro fractures.

An Environment Friendly Approach to Reduce the Breakdown Pressure of High Strength Unconventional Rocks by Cyclic Hydraulic Fracturing

2019 ◽  
Vol 142 (4) ◽  
Author(s):  
Zeeshan Tariq ◽  
Mohamed Mahmoud ◽  
Abdulazeez Abdulraheem ◽  
Dhafer Al-Shehri ◽  
Mobeen Murtaza
Keyword(s):  
Hydraulic Fracturing ◽  
High Strength ◽  
Progressive Increase ◽  
New Method ◽  
Hydraulic Fractures ◽  
Breakdown Pressure ◽  
Environment Friendly ◽  
Rock Types ◽  
Pressurization Rate ◽  
Tight Rocks

Abstract Unconventional hydrocarbon resources mostly found in highly stressed, overpressured, and deep formations, where the rock strength and integrity are very high. When fracturing these kinds of rocks, the hydraulic fracturing operation becomes much more challenging and difficult and in some cases reaches to the maximum pumping capacity limits without generating any fracture. This reduces the operational gap to optimally place the hydraulic fractures. Current stimulation methods to reduce the fracture pressures involvement with adverse environmental effects and high costs due to the entailment of water mixed with huge volumes of chemicals. In this study, a new environment friendly approach to reduce the breakdown pressure of the unconventional rock is presented. The new method incorporates the injection of chemical-free fracturing fluid in a series of cycles with a progressive increase of the pressurization rate in each cycle. This study is carried out on different cement blocks with varying petrophysical and mechanical properties to simulate real rock types. The results showed that the new method of cyclic fracturing can reduce the breakdown pressure to 24.6% in ultra-tight rocks, 19% in tight rocks, and 14.8% in medium- to low-permeability rocks. This reduction in breakdown pressure helped to overcome the operational challenges in the field and makes the fracturing operation much greener.

A Novel Design Method for Optimizing the Diverter Dosage in Hydraulic Fracturing Using Three-Dimensionally Printed Fractures

2021 ◽  
Author(s):  
Meng Wang ◽  
Mingguang Che ◽  
Bo Zeng ◽  
Yi Song ◽  
Yun Jiang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Design Method ◽  
Pressure Rise ◽  
Horizontal Wells ◽  
Optimization Method ◽  
Darcy Law ◽  
Hydraulic Fractures ◽  
Fracture Conductivity ◽  
Fracture Simulation ◽  
3D Printed

Abstract Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to simulate the fracture in Temco fracture conductivity system to mimic the practical treatment to temporarily plugging the fracture. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70° could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells (averaging TVD 3600 m) was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.

Time-Dependent Initiation of Multiple Hydraulic Fractures in a Formation With Varying Stresses and Strength

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1317-1325 ◽  
Author(s):  
Andrew P. Bunger ◽  
Guanyi Lu
Keyword(s):  
Tensile Strength ◽  
Hydraulic Fracture ◽  
Fracture Initiation ◽  
Time Frame ◽  
Hydraulic Fractures ◽  
Static Fatigue ◽  
Breakdown Pressure ◽  
Initiation Point ◽  
Delayed Failure ◽  
Wellbore Pressure

Summary The premise of classical hydraulic-fracture-breakdown models is that hydraulic-fracture growth can only start when the wellbore pressure reaches a critical value that is sufficient to overcome the tensile strength of the rock. However, rocks are well-known to exhibit static fatigue; that is, delayed failure at stresses less than the tensile strength. In this paper, we explore the consequences of delayed failure on axially oriented initiation of multiple hydraulic fractures. Specifically, given a certain breakdown pressure, we investigate the conditions under which subsequent hydraulic fracture(s) can begin within the time frame of a stimulation treatment in regions of higher stress and/or strength because of delayed-failure mechanisms. The results show that wells completed in shallower formations are more sensitive to variations in strength, whereas wells completed in deeper formations are more sensitive to variations in stress. Furthermore, cases in which all hydraulic fractures break down according to the same pressurization regime—that is, all are “fast” (nonfluid-penetrating) pressurization or else all are “slow” (uniformly pressurized fluid-penetrating) pressurization cases—are highly sensitive to small stress/strength variability. On the other hand, if the first hydraulic-fracture initiation is in the “fast”-pressurization regime and subsequent fracture(s) are in the “slow”-pressurization regime, then the system is robust to a much-higher degree of variability in stress/strength. Practically, this work implies that methods aimed at moderately reducing the variability in stress/strength among the possible initiation points (i.e., perforation clusters) within a particular stage can have a strong effect on whether multiple hydraulic fractures will begin. In addition, this analysis implies that pumping strategies that encourage “fast,” nonpenetrative breakdown of the first initiation point followed by the opportunity for fluid-penetrating, “slow” breakdown of subsequent initiation points could be effective at encouraging multiple-hydraulic-fracture initiation.

The effect of stress on the primary permeability of rock cores—a facet of hydraulic fracturing

1981 ◽  
Vol 18 (2) ◽  
pp. 195-204 ◽  
Author(s):  
R. Heystee ◽  
J.-C. Roegiers
Keyword(s):  
Rock Mass ◽  
Hydraulic Fracturing ◽  
The State ◽  
Stress Conditions ◽  
Breakdown Pressure ◽  
Rock Types ◽  
State Of Stress ◽  
Pressurization Rate ◽  
Fluid Penetration ◽  
Fracturing Experiments

Recent laboratory hydraulic fracturing experiments have shown that fluid penetration into the rock mass adjacent to the borehole being pressurized has a significant influence on the magnitude of the breakdown pressure. One factor affecting the degree of penetration of the pressurizing fluid is the permeability of the rock mass, which in turn is a function of the state of stress present in the rock mass. To study this permeability–stress relationship, a radial permeameter was constructed and three rock types tested. Derived expressions show that during radially divergent and convergent flow in the permeameter, the state of stress in the rock specimen is tensile and compressive respectively. The radial permeameter test results show that the permeability of rock increases significantly under tensile stress conditions and reduces under compressive stress conditions. The results from this study were used to develop a conceptual model which explains the dependency of breakdown pressure levels on the pressurization rate.

scholarly journals Numerical Investigation of Injection-Induced Fracture Propagation in Brittle Rocks with Two Injection Wells by a Modified Fluid-Mechanical Coupling Model

Energies ◽  
2020 ◽  
Vol 13 (18) ◽  
pp. 4718
Author(s):  
Song Wang ◽  
Jian Zhou ◽  
Luqing Zhang ◽  
Zhenhua Han
Keyword(s):  
Fracture Propagation ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Fracture Networks ◽  
Breakdown Pressure ◽  
Injection Wells ◽  
Mechanical Coupling ◽  
Stress Shadow ◽  
Well Spacing

Hydraulic fracturing is a key technical means for stimulating tight and low permeability reservoirs to improve the production, which is widely employed in the development of unconventional energy resources, including shale gas, shale oil, gas hydrate, and dry hot rock. Although significant progress has been made in the simulation of fracturing a single well using two-dimensional Particle Flow Code (PFC2D), the understanding of the multi-well hydraulic fracturing characteristics is still limited. Exploring the mechanisms of fluid-driven fracture initiation, propagation and interaction under multi-well fracturing conditions is of great theoretical significance for creating complex fracture networks in the reservoir. In this study, a series of two-well fracturing simulations by a modified fluid-mechanical coupling algorithm were conducted to systematically investigate the effects of injection sequence and well spacing on breakdown pressure, fracture propagation and stress shadow. The results show that both injection sequence and well spacing make little difference on breakdown pressure but have huge impacts on fracture propagation pressure. Especially under hydrostatic pressure conditions, simultaneous injection and small well spacing increase the pore pressure between two injection wells and reduce the effective stress of rock to achieve lower fracture propagation pressure. The injection sequence can change the propagation direction of hydraulic fractures. When the in-situ stress is hydrostatic pressure, simultaneous injection compels the fractures to deflect and tend to propagate horizontally, which promotes the formation of complex fracture networks between two injection wells. When the maximum in-situ stress is in the horizontal direction, asynchronous injection is more conducive to the parallel propagation of multiple hydraulic fractures. Nevertheless, excessively small or large well spacing reduces the number of fracture branches in fracture networks. In addition, the stress shadow effect is found to be sensitive to both injection sequence and well spacing.

Assessment of Seismic Risk in Geothermal and Hydrocarbon Reservoirs Using an Exact Analytical Solution of Stress Change

2021 ◽  
Author(s):  
Paul Jacob van den Hoek ◽  
Jorik Willem Poessé
Keyword(s):  
Finite Element ◽  
Analytical Solution ◽  
Seismic Risk ◽  
Exact Analytical Solution ◽  
Pressure Rise ◽  
Geothermal Field ◽  
Hydrocarbon Reservoirs ◽  
Pressure Effects ◽  
Steam Flooding ◽  
Stress Changes

Abstract Both for the oil & gas and geothermal industry, induced seismicity caused by field development and operation can pose a risk, in particular when the reservoir (or overburden / underburden) is intersected by faults. The mechanisms by which faults can be reactivated (potentially leading to seismicity) include pressure effects (reservoir depletion, or pressure rise over large areas as a result of injection) or thermal effects (cooling such as in geothermal operations or heating such as in steam flooding). Earlier, we proposed a simple methodology to assess seismic risk for geothermal reservoirs that can also be applied to hydrocarbon reservoirs. This methodology uses an elastoplastic finite element model of the reservoir in question. However, its application turned out to be laborious. Therefore, we developed an exact analytical solution for the stress changes induced by cooling, depletion and /or pressurization along (a) representative fault(s). This solution is a generalisation of the Goodier analytical solution for the situation of non-vertical faults. The analytical solution can be used to quickly evaluate a number of different scenarios related to temperature and /or pressure distributions in the reservoir. In the case of fault activation, maximum fault displacements (slip) can be computed by linking the results to elastic finite element calculations for similar load conditions. Using published standard correlations, the seismic magnitude can subsequently be estimated from the computed fault displacements. The analytical model was applied to different fault geometries, reservoir temperature distributions and depletions. It turns out that certain fault geometries (dip angles, offsets) are far more prone to activation than other fault geometries. An explanation of this result is provided. Furthermore, for non-critically stressed faults, the risk of activation is far less for geothermal operations than for situations where large parts of the reservoir are depleted or pressurized. This can be explained by the fact that the extent of the cooled zone in geothermal operations is generally limited, even after 30 years of operation. Consequently, cooling-induced stress changes along the fault are significantly reduced because of arching by the adjacent non-cooled areas. Finally, one geothermal field example in The Netherlands is presented where the above methodology was applied to demonstrate that there exists no seismic risk over the entire field life.

scholarly journals Effect of Joint Geometrical Parameters on Hydraulic Fracture Network Propagation in Naturally Jointed Shale Reservoirs

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-23 ◽  
Author(s):  
Zhaohui Chong ◽  
Qiangling Yao ◽  
Xuehua Li
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Geometrical Parameters ◽  
Breakdown Pressure ◽  
Opening Mode ◽  
Hydraulic Fracture Network ◽  
Shale Reservoirs ◽  
Network Pattern

The presence of a significant amount of discontinuous joints results in the inhomogeneous nature of the shale reservoirs. The geometrical parameters of these joints exert effects on the propagation of a hydraulic fracture network in the hydraulic fracturing process. Therefore, mechanisms of fluid injection-induced fracture initiation and propagation in jointed reservoirs should be well understood to unleash the full potential of hydraulic fracturing. In this paper, a coupled hydromechanical model based on the discrete element method is developed to explore the effect of the geometrical parameters of the joints on the breakdown pressure, the number and proportion of hydraulic fractures, and the hydraulic fracture network pattern generated in shale reservoirs. The microparameters of the matrix and joint used in the shale reservoir model are calibrated through the physical experiment. The hydraulic parameters used in the model are validated through comparing the breakdown pressure derived from numerical modeling against that calculated from the theoretical equation. Sensitivity analysis is performed on the geometrical parameters of the joints. Results demonstrate that the HFN pattern resulting from hydraulic fracturing can be roughly divided into four types, i.e., crossing mode, tip-to-tip mode, step path mode, and opening mode. As β (joint orientation with respect to horizontal principal stress in plane) increases from 0° to 15° or 30°, the hydraulic fracture network pattern changes from tip-to-tip mode to crossing mode, followed by a gradual decrease in the breakdown pressure and the number of cracks. In this case, the hydraulic fracture network pattern is controlled by both γ (joint step angle) and β. When β is 45° or 60°, the crossing mode gains dominance, and the breakdown pressure and the number of cracks reach the lowest level. In this case, the HFN pattern is essentially dependent on β and d (joint spacing). As β reaches 75° or 90°, the step path mode is ubiquitous in all shale reservoirs, and the breakdown pressure and the number of the cracks both increase. In this case, β has a direct effect on the HFN pattern. In shale reservoirs with the same β, either decrease in k (joint persistency) and e (joint aperture) or increase in d leads to the increase in the breakdown pressure and the number of cracks. It is also found that changes in d and e result in the variation in the proportion of different types of hydraulic fractures. The opening mode of the hydraulic fracture network pattern is observed when e increases to 1.2 × 10−2 m.

scholarly journals A multi-perforation staged fracturing experimental study on hydraulic fracture initiation and propagation

2020 ◽  
Vol 38 (6) ◽  
pp. 2466-2484
Author(s):  
Jianguang Wei ◽  
Saipeng Huang ◽  
Guangwei Hao ◽  
Jiangtao Li ◽  
Xiaofeng Zhou ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Initiation ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Breakdown Pressure ◽  
Tight Sandstone ◽  
Heterogeneous Samples ◽  
Initiation And Propagation

Hydraulic fracture initiation and propagation are extremely important on deciding the production capacity and are crucial for oil and gas exploration and development. Based on a self-designed system, multi-perforation cluster-staged fracturing in thick tight sandstone reservoir was simulated in the laboratory. Moreover, the technology of staged fracturing during casing completion was achieved by using a preformed perforated wellbore. Three hydraulic fracturing methods, including single-perforation cluster fracturing, multi-perforation cluster conventional fracturing and multi-perforation cluster staged fracturing, were applied and studied, respectively. The results clearly indicate that the hydraulic fractures resulting from single-perforation cluster fracturing are relatively simple, which is difficult to form fracture network. In contrast, multi-perforation cluster-staged fracturing has more probability to produce complex fractures including major fracture and its branched fractures, especially in heterogeneous samples. Furthermore, the propagation direction of hydraulic fractures tends to change in heterogeneous samples, which is more likely to form a multi-directional hydraulic fracture network. The fracture area is greatly increased when the perforation cluster density increases in multi-perforation cluster conventional fracturing and multi-perforation cluster-staged fracturing. Moreover, higher perforation cluster densities and larger stage numbers are beneficial to hydraulic fracture initiation. The breakdown pressure in homogeneous samples is much higher than that in heterogeneous samples during hydraulic fracturing. In addition, the time of first fracture initiation has the trend that the shorter the initiation time is, the higher the breakdown pressure is. The results of this study provide meaningful suggestions for enhancing the production mechanism of multi-perforation cluster staged fracturing.

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