Fracture Pressure Research Articles

Characterization methods for current in-situ stress in oil and gas reservoirs: a mini review

In-situ stress plays a crucial role in governing various parameters such as the distribution of oil and gas accumulation zones, the fracture pattern of reservoirs, formation fracture pressure, and collapse pressure. Understanding the distribution characteristics of current in situ stress of reservoirs has significant implications for exploration and development of oil and gas. This paper focuses on the characterization methods for current in situ stress of oil and gas reservoirs, discussing the research progress in testing methods, computational approaches, numerical simulations, and seismic prediction methods. The results indicate that the testing method including the on-site testing method and the laboratory testing method offer the relatively high accuracy, but this method only provides point-specific magnitude and direction of current in situ stress. The Computational approaches can obtain continuous profiles of current in situ stress along individual wells. After using the testing method for calibration, we can obtain relatively accurate calculation results. The numerical method can predict current in situ stress over large areas, but it requires rigorous model setup, boundary definition, and parameter selection. The seismic prediction method also can predict broad distribution of current in situ stress, but this method is influenced by many factors and we had better apply this method in conjunction with other methods. In the future, engineers and researchers should innovate testing technologies and instruments, and establish models and processes for joint use of multiple methods, and explore the development of novel current in situ stress prediction models based on artificial intelligence and big data.

New Mathematical Technique for Step Rate Test Analysis Aids Determination of Fracture Pressure and Overcomes the Uncertainty of Conventional Analysis.

Experience in the oil industry has shown that it is challenging to sustain successful long-term matrix injection, as injection water quality cannot be maintained rigorously due to facility hiccups and membrane clogging. Most oil field operators have resolved this problem of injectivity decline by increasing the surface injection pressure to part the formation and inject just above the fracture gradient with strict offtake management for zonal conformance. This is not an easy task as injection much above fracture opening pressure can lead to water fingering and poor sweep that results in uneconomical waterflood recovery. The operators, thus, strive to inject at a pressure just above the fracture opening pressure so that the fracture opens near the wellbore but does not extend and then maintain the pressure just above the fracture closing pressure. Therefore, determination of the fracture opening pressure and fracture closing pressure has remained critical data for the success of waterflood projects. The most reliable industry approach to estimating fracture opening and fracture closing pressures comes from the step rate test (SRT). This traditional approach of Cartesian analysis of pressure-rate plot fits straight lines through the data in a plot of injection pressure against injection rate and then estimates the fracture pressure from the intersection of these lines having different slopes. The data received often do not exhibit one clear change in slope, thus resulting in multiple possible solutions, making it difficult for the operator to use the data for high CAPEX facilities design. Most past studies indicate the subjectivity of this Cartesian slope fitting technique. Alternative solutions through multirate superposition analysis found limited application in the analysis of SRT data due to considerable sensitivity to the value of initial pressure used for superposition and lack of stability of rate and pressure data. In this article, a new technique of SRT analysis is presented, which provides a unique solution for fracture opening and fracture closing pressures. It helps to overcome the limitations of the traditional technique of arbitrary fitting of straight lines. It uses the mathematical understanding of cumulative derivatives to recognize that the matrix opens when the cumulative growth of the rate of injectivity shows a change. It estimates the derivative of the injection rate with respect to injection pressure at each step. Then, it estimates the fracture pressure from the plot of the cumulative of this derivative against pressure at each step. It helps to overcome the challenge SRT solutions posed by the nonlinear trend of pressure data at each injection step both before fracture and after fracture is initiated. It also overcomes the limitations of the multirate superposition technique, as it is not sensitive to the value of initial pressure used for superposition.

Dynamic modeling of geological carbon storage in an oil reservoir, Bredasdorp Basin, South Africa

Geological carbon storage provides an efficient technology for the large-scale reduction of atmospheric carbon, and the drive for net-zero emissions may necessitate the future usage of oil reservoirs for CO2 projects (without oil production), hence, dynamic modeling of an oil reservoir for CO2 storage in the Bredasdorp basin, South Africa, was therefore conducted. Injection into the reservoir was for 20 years (2030–2050), and 100 years (2050–2150) to study the CO2–brine–oil interactions, with sensitivities carried out on reservoir boundary conditions. The closed boundary scenario experienced pressure buildup with a target injection rate of 0.5 Mt/year, and a cutback on injection rate progressively until 2050 to not exceed the fracture pressure of the reservoir. The CO2 plume migration was not rapid due to the reduced volume of CO2 injected and the confining pressure. The system was gravity dominated, and gravity stability was not attained at the end of the simulation as fluid interfaces were not yet flat. The open boundary reservoir did not experience a pressure buildup because all boundaries were open, the target injection rate was achieved, and it was a viscous-dominated system. In both cases, the dissolution of CO2 in oil and brine was active, and there was a growing increase of CO2 fraction dissolved in water and oil, a decline in gaseous mobile CO2 phase between 2050 and 2150, and active trapping mechanisms were structural trapping, dissolution in oil and water, and residual trapping. The study showed that boundary condition was very crucial to the success of the project, with direct impacts on injection rate and pressure. This pioneering study has opened a vista on the injection of CO2 into an oil reservoir, and CO2–brine–oil interactions, with sensitivities carried out on reservoir boundary conditions in a closed and an open hydrocarbon system in South Africa.

A multi-scale geological–engineering sweet spot evaluation method for tight sandstone gas reservoirs

Exploration and development practices have proved that staged volumetric fracturing stimulation in horizontal wells is a key technology for tight sandstone gas development, and reservoir sweet spot is an important basis for the perforation position selection and staged fracturing in the process of well location deployment and reservoir stimulation. Tight sandstone reservoirs are usually characterized by sandstone and mudstone interlayers with different thicknesses, and complex natural fracture distribution and geostress state. It is hard to predict “geological-engineering” dual sweet spots, and these two kinds of sweet spots are usually in different zones. As a result, there lacks a basis for the optimization of fracturing parameters to stimulate tight sandstone reservoirs. This paper establishes a geological sweet spot prediction model which takes into account total hydrocarbon content, reservoir porosity and other factors, then puts forward a 3D multi-scale engineering sweet spot evaluation method which takes into account lithology, fracture morphology, fracture mechanical behavior, and dilatation and shear dilation effect, and finally a “geological-engineering” dual sweet spot evaluation model for tight sandstone reservoirs. Two wells in the tight sandstone gas field in the Linxing Block of the Ordos Basin were selected as a case, and the dual sweet spot profiles, fracturing pressure and SRV were compared and analyzed. The results show that: 1) shear dilation angle influences the distribution of engineering sweet spots at the most in the study area, followed by dissipated energy, elastic modulus and fracture energy; 2) the geological sweet spot zone with a high coefficient is not necessarily the pay zone with high shale gas production; 3) the engineering sweet spot zone with a high coefficient needs lower fracture pressure and can be stimulated relatively sufficiently; 4) high-quality geological sweet spots and high-quality engineering sweet spots are poorly consistent in spatial location. In conclusion, the stimulation of tight sandstone gas reservoirs shall take geological sweet spot as the basis and engineering sweet spot as the guarantee, and the distribution of dual sweep spots should be considered comprehensively. The multi-scale “geological-engineering” dual sweet spot evaluation method proposed in this paper provides important technical support for the prediction of sweet spots of the tight sandstone gas and the optimization of development schemes in the study area.

Rate-dependent damage evolution and crack branching of pipe under internal gaseous detonation loading

A rate-dependent damage evolution law was derived based on the thermally activated motion of dislocations. By writing the VUMAT subroutine, it was implemented to simulate the dynamic crack propagation and branching of pipe due to internal gaseous detonation. Also, the fluid-structure coupling between detonation wave and pipe was well achieved through immersed boundary method and “softened” contact formula. The predicted fracture profiles and pressure history inside the pipe were validated with experiments and compared with available results in literatures. Results demonstrated that the developed numerical model was more accurate in predicting the dynamic crack behaviors, especially the crack branching position relative to the main crack tip. The simulated average crack speed ranged from 171 m/s to 228 m/s, which well fell within the experimental range. Instead of dramatically decreasing, the speed of branched crack was comparable to that of the main crack. The damage field around the crack tip can reflect the direction of crack propagation or branching. The maximum strain rate always appeared at the right front of crack tip regardless of the subsequent crack behavior. It was further revealed that the high strain rate contributed to the straight propagation of crack, while branching was primarily governed by the particular strain pattern around the crack tip.

Feasibility Assessment of Acid Gas Injection in an Iranian Offshore Aquifer

Acid gas injection operations function as the commercial equivalent of certain aspects within the realm of geological CO2 storage. Acid gas, composed of H2S and CO2, alongside minor quantities of hydrocarbon gases stemming from either petroleum production or processing, constitute the composition of acid gas. The primary aim of acid gas injection operations lies in the disposal of H2S. Nevertheless, substantial volumes of CO2 are concurrently injected due to the economic impracticality of segregating the two gases. This investigation delves into the comprehensive, step-by-step procedure that can be employed to determine the suitability of a field or formation for acid gas injection, utilizing all accessible data, including the literature and data from neighboring fields. This approach incorporates sensitivity analysis of various parameters to ascertain the feasibility of AGI while minimizing costs and time consumption. The focus of this study centers on evaluating the feasibility of Acid Gas Injection (AGI) in a saline aquifer offshore in Iran. The assessment encompasses the examination of reservoir properties, geomechanical aspects, caprock integrity, and gas plume dynamics. The Surmeh formation emerges as a promising candidate for AGI due to the presence of upper dolomite and lower carbonate within the rock formations. Geomechanical analysis reveals a pore pressure of 3800 psi and a fracture pressure of 6100 psi. Caprock integrity, particularly within the Hith formation, emerges as pivotal for both containment and long-term stability. Seismic mapping highlights variations in caprock thickness, influencing containment effectiveness. Capillary trapping emerges as a significant factor in short-term gas entrapment and plume distribution. Numerical simulations elucidate the impact of heterogeneous rock properties on capillary trapping and gas plume movement. The projection estimates approximately 2 TCF (Trillion Cubic Feet) of acid gas injection into the Surmeh formation. Based on the acid gas content and the gas in place at the source of injection, the recommended injection rate stands at 180 MMSCFD (million standard cubic feet per day). The formation’s inherent tightness limits injectivity, allowing for a maximum achievable rate of 7 MMSCFD with a permeability of 1 mD (millidarcy). However, a higher porosity (12%) and a permeability of 100 mD enable more efficient injection without fracturing the formation. To achieve this, it becomes imperative to implement two injection wells, each with a capacity of 90 MMSCFD.

Comparison of interfragmentary compression across simulated condylar fractures repaired using four techniques.

Equine condylar fractures are commonly repaired using cortex screws applied in lag fashion. Inadequate interfragmentary compression can lead to post-operative complications. Lateral condylar fractures were simulated in 21 cadaver limbs (8 third metatarsals, 13 third metacarpals). In each limb, pressure-sensitive film (Prescale®, Fuji Photo Film Co.) was placed in each osteotomy prior to repair with 4.5 mm diameter cortex screws placed in lag fashion. Screws were placed in linear (L), triangular (T), linear plus a washer (LW) and sequentially tightened triangular configurations (TD1). All screws were tightened to a torque of 4 Nm. Pressure prints obtained were scanned using dedicated software (Fuji FPD-8010E, Fuji Photo Film Co.). A Bayesian Network (BN) model was developed to investigate the impact and interrelationship of each factor on interfragmentary compression. Sixty-three repairs (20*L, 24* T, 11*TD1, and 8*LW) performed on 21 limbs were included in the analysis. The BN predicted mean contact area (±s.d.) for pressures within the operating range of the prescale film [≥2.5 Megapascals (MPa) ≤ 10 MPa] by L, T, TD1 and LW repairs were 403mm2 ± (140), 411 mm2 ± (120), 403 mm2 ± (120), and 366mm2 ± (70). The mean contact area (± s.d.) created by L, T, TD1 and LW repairs at pressures >10 MPa were 112 mm2 ± (48), 167 mm2 ± (67), 142 mm2 ± (50), and 100mm2 ± (27). When pressures ≥2.5 MPA to ≤10 MPa were considered, the construct (T or L), washer and screw tightening sequence variables had a very low effect on interfragmentary contact area. At pressures >10 MPa BN sensitivity findings were 16.3, 5.03, and 0.133% for construct, washer and screw tightening sequence. The BN model indicated that triangular repair configuration had a weak influence in the ≥2.5 MPa ≤ 10 MPa range and a moderate influence in the <10 MPa range, on interfragmentary compression. The addition of a washer and the screw tightening sequence had a weak influence on interfragmentary compression at all pressure ranges. The results show that triangular repairs create larger interfragmentary contact areas at greater interfragmentary pressure in simulated condylar fractures, however it is unknown if this results in improved repair stability in the clinical scenario.

Temporary Plugging Agent Evaluation Technology and Its Applications in Shale Reservoirs in the Sichuan Basin

Shale oil reservoirs in the Daanzhai section of central Sichuan are mainly developed in the Daer subsection, with a rich resource base and great exploration and development potential. However, the shale oil reservoir is characterized by shale and limestone interactions, poor physical properties, undeveloped fractures, and large differences in the fracture pressure of interactive reservoirs. Therefore, it is necessary to use temporary plugging and diverting fracturing technology to improve the complexity of fractures in reservoir reconstruction. To this end, an experimental device was innovatively established that takes into account the morphology of fractures and the permeability of reservoirs, and it can evaluate the temporary blocks and turns within third-level fractures in a reservoir. It can simulate third-level turning fractures under conditions involving 3–15 mm crack openings and different roughness values. Using this device and method, the combination and particle-size optimization experiments involving the temporary plugging agents used in the field were carried out, and the field tests were carried out in Well Long’an 1 and Well Ren’an 1 in the Sichuan Basin. The test results show that the pressure response after temporary plugging is obvious, which can significantly improve microseismic event points and increase the reservoir’s reconstruction volume. Compared with Well Nanchong 2H, the length in kilometers of the SRV after tackling key problems increases from 3918 × 104 m3 to 4578 × 104 m3, an increase of 17%. The average crack length increased from 265 m to 321 m, an increase of 21%, achieving a significant breakthrough in the “oil production gap”.

Fracture geometry and breakdown pressure of radial borehole fracturing in multiple layers

Radial borehole fracturing that combines radial boreholes with hydraulic fracturing is anticipated to improve the output of tight oil and gas reservoirs. This paper aims to investigate fracture propagation and pressure characteristics of radial borehole fracturing in multiple layers. A series of laboratory experiments with artificial rock samples (395 mm × 395 mm × 395 mm) was conducted using a true triaxial fracturing device. Three crucial factors corresponding to the vertical distance of adjacent radial borehole layers (vertical distance), the azimuth and diameter of the radial borehole are examined. Experimental results show that radial borehole fracturing in multiple layers generates diverse fracture geometries. Four types of fractures are identified based on the connectivity between hydraulic fractures and radial boreholes. The vertical distance significantly influences fracture propagation perpendicular to the radial borehole axis. An increase in the vertical distance impedes fracture connection across multiple radial borehole layers and reduces the fracture propagation distance along the radial borehole axis. The azimuth also influences fracture propagation along the radial borehole axis. Increasing the azimuth reduces the guiding ability of radial boreholes, which makes the fracture quickly curve to the maximum horizontal stress direction. The breakdown pressure correlates with diverse fracture geometries observed. When the fractures connect multi-layer radial boreholes, increasing the vertical distance decreases the breakdown pressure. Decreasing the azimuth and increasing the diameter also decrease the breakdown pressure. The extrusion force exists between the adjacent fractures generated in radial boreholes in multiple rows, which plays a crucial role in enhancing the guiding ability of radial boreholes and results in higher breakdown pressure. The research provides valuable theoretical insights for the field application of radial borehole fracturing technology in tight oil and gas reservoirs.

Waterflood-induced fracture or "Two-Step-Rate-Test" to improve reservoir injectivity

Low permeability reservoirs (less than 1 mD) are developed by intensive waterflooding. The agent is injected at pressures higher than the fracturing pressure, so that in almost every well involved in this procedure, there is spontaneous growth (injection) of artificial fractures in different directions with different characteristics, and so on. The relevance of the topic is due to a new procedure called two-stage reservoir injectivity enhancement using multiple injection modes, this technique is used to determine the test fluid injection pressure at which fracture growth will occur. The problem of this study is to increase the injectivity of the injection well in order to increase fluid production. The aim and purpose of the work is the process of increasing the injectivity of injection wells by "steps" (Step-Rate-Test is SRT): a study of the Tevlinsko-Russkinskoye field. The moment of autofracturing is determined by SRT and not by injectivity. The method of interpretation is plotting. The difference between SRT and 2-SRT is considered, the 2-SRT well treatment is carried out, the efficiency of the applied method and the results of the work are presented.

Strain Field Characteristics of Coal-like Material under CO2 Fracturing.

Considering the problems related to hydrofracturing, CO2 fracturing is a more effective way to enhance the permeability of coal seams. Conventional research has focused on the dynamic behavior of coal and rock under CO2 fracturing. There is a lack of quantitative descriptions of the fracturing stages. Therefore, CO2 fracturing experiments were carried out with coal-like material at several pressures. The maximum principal strain field was obtained by analyzing the surface images of the specimens. Nine characteristic parameters of typical grayscale and texture images were calculated from the strain field. The correlation between the maximum principal strain and the characteristic parameters was examined using gray relational analysis, and the effects of pressure on those parameters were investigated. We obtained some interesting results, for example, the standard deviation increased from 50 to 100, and kurtosis decreased from -1.0 to -1.5 with the fracturing pressure. The thresholds of the characteristic function F at different fracturing stages were determined, too. This research provides a basis for designing the drilling hole location and determining the millisecond delay of multihole fracturing, as well as for automatically dividing the fracturing stages with artificial intelligence based on the maximum principal strain field.

A semi-analytical flowback data history-matching approach that rigorously accounts for fracture dynamics

Flowback data analysis methods used for unconventional reservoirs are still in their infancy. Until now, the dynamics of fracture closure during flowback have not been rigorously accounted for in analytical or semi-analytical models. In some cases, at the start of flowback, fracture pressure may be higher than the minimum horizontal stress, which means the fracture is still closing during the early flowback period. For such cases, the commonly-applied assumption of a static fracture width in flowback modeling will be in significant error. Moreover, previous analytical and semi-analytical modeling approaches have ignored fluid leakoff from the fracture when the fracture pressure is greater than reservoir pressure, which could also lead to significant errors when analyzing early flowback data in a stress-sensitive reservoir.In the current work, a semi-analytical history-matching approach for characterizing hydraulic fractures, which captures the dynamic behavior of hydraulic fractures during the early production period, is presented. The proposed methodology accounts for varying fracture width, cumulative leakoff from the fracture to the matrix, and spontaneous imbibition, during early flowback. The new method is verified using numerically simulated data and its practical application demonstrated by history matching a field case (shale gas well) exhibiting evidence of dynamic fracture properties during flowback. History matching of the same field case using models that do not account for fracture dynamics or fluid leakoff reveals that these models may overestimate fracture properties such as initial fracture permeability. In addition, history matching of the field case with the new model without spontaneous imbibition effects implemented yields fracture properties (initial fracture permeability and fracture half-length) that are greater than when both geomechanics and spontaneous imbibition are implemented.When compared to existing flowback models, the proposed semi-analytical model may yield more accurate estimates of fracture properties when fracture dynamics cannot be ignored during the early flowback period.

A new robust predictive model for lost circulation rate using convolutional neural network: A case study from Marun Oilfield

A major cause of some of serious issues encountered in a drilling project, including wellbore instability, formation damage, and drilling string stuck – which are known to increase non-productive time (NPT) and hence the drilling cost – is what we know as mud loss. The mud loss can be prevented or at least significantly reduced by taking proper measures beforehand provided the position and intensity of such loss can be properly predicted using an accurate predictor model. Accordingly, in this study, we used the convolutional neural network (CNN) and hybridized forms of multilayer extreme learning machine (MELM) and least square support vector machine (LSSVM) with the Cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithm (GA) for modeling the mud loss rate based on drilling data, mud properties, and geological information of 305 drilling wells penetrating the Marun Oilfield. For this purpose, we began by a pre-processing step to attenuate the effect of noise using the Savitzky-Golay method. The whole set of available data was divided into the modeling (including 2300 data points) and the validation (including 483 data points) subsets. Next, the second generation of the non-dominated sorting genetic algorithm (NSGA-II) was applied to the modeling data to identify the most significant features for estimating the mud loss. The results showed that the prediction accuracy increased with the number of selected features, but the increase became negligible when the number of selected features exceeded 9. Accordingly, the following 9 features were selected as input to the intelligent algorithms (IAs): pump pressure, mud weight, fracture pressure, pore pressure, depth, gel 10 min/gel 10 s, fan600/fan300, flowrate, and formation type. Application of the hybrid algorithms and simple forms of LSSVM and CNN to the training data (80% of the modeling data, i.e. 1840 data points) showed that all of the models tend to underestimate the mud loss at higher mud loss rates, although the CNN exhibited lower underestimation levels. Error analysis on different models showed that the CNN provided for a significantly higher degree of accuracy, as compared to other models. The more accurate outputs of the hybrid LSSVM model than those of the simple LSSVM indicated the large potentials of metaheuristic algorithms for achieving optimal solutions. The lower error levels obtained with the CNN model in the testing phase highlighted the excellent generalizability of this model for unseen data. The more accurate predictions obtained with this model, rather than the other models, in the validation phase further proved this latter finding. Therefore, application of this method to other wells in the same field is highly recommended.

Calculation of Wellbore Fracture Pressure Under Multi Field Coupling Based on M-Integral of Configuration Mechanics

Calculation of Wellbore Fracture Pressure Under Multi Field Coupling Based on M-Integral of Configuration Mechanics

Bayesian decision making using partial data for fractured poroelastic media

Partial data is a common challenge in many applied problems, where we can measure only the part of the solution. This paper considers the poroelasticity problem in fractured media, where only partial measurements of fracture pressures are available. The poroelasticity models have applications in many engineering and scientific fields, such as geomechanics, hydrology, and reservoir simulation. This paper aims to develop a Bayesian decision making approach using partial data and consider its application to the poroelasticity problem in fractured media. The methodology of the proposed approach combines Proper Orthogonal Decomposition, Discrete Empirical Interpolation Method, Bayesian Inversion Approach, and Bayesian Decision Theory. It allows us to compute posterior probabilities and decide according to the optimal decision rule based on the partial data. Moreover, we apply partially explicit temporal discretization to solve forward problems efficiently. For testing the proposed approach, we consider a two-dimensional model problem. We simulate the cases when we need to make a single decision about the reservoir or decisions about the elements of the set of reservoirs. The results show that the proposed approach can efficiently compute the posterior probabilities and make a decision in the presence of only partial data for both cases.

Comparative experimental investigation on permeability and pressure bearing capacity of different types of temporary plugging bodies

Temporary plugging and diversion fracturing technology play a vital role in boosting the production of tight reservoirs. The increase of net pressure in fractures is the core of temporary plugging diversion fracturing, which is closely related to the permeability of temporary plugging aggregates. However, the evolution of the permeability of temporary plugging bodies has received limited research attention. In this paper, a novel experimental system for evaluating the permeability capacity of temporary plugging agents is firstly established. This device allows us to measure critical parameters such as injection pressure, length and permeability of the temporary plugging body during the experimentation. Additionally, we assess the pressure-bearing capacity of the temporary plugging agent using a specialized experimental setup for temporarily plugging fractures. Throughout the experiment, we collect data on time consumption at different pressure levels and the volume of injected liquid. Furthermore, we conduct a comparative analysis of the pressure-bearing effects of five types of temporary plugging materials. Our experimental results reveal some interesting findings. Pure granular CDD-1 does not effectively form a substantial length, and we observe no significant relationship between the length and permeability of the temporary plugging body. In contrast, temporary plugging materials mainly composed of powder exhibit a uniform permeability of the temporary plugging body, blending both powder and particles. Moreover, temporary plugging bodies primarily formed by powder, uniform mixtures of powder and particles, and predominantly particle-based plugging bodies (with consideration of powder) demonstrate lower permeability, rendering them more favorable for temporary plugging purposes. This study sheds light on the permeability characteristics of different temporary plugging materials, contributing to a better understanding of their efficacy in temporary plugging and diversion fracturing applications. The findings could inform the selection and optimization of temporary plugging agents, ultimately enhancing the efficiency and success of tight reservoir production.

Frac-Hit Prevention Countermeasures in Shale Gas Reservoirs with Natural Fractures

The development of natural fractures (NFs) in shale gas reservoirs is conducive to improving the productivity of shale gas wells. However, NF development leads to high-frequency frac hits between the infill and parent wells, which critically restricts its efficiency. To elucidate the large contribution of hydraulic fractures (HFs) and NFs in frac hits during the production and the development of NF-developed shale gas reservoirs, such reservoirs in the WY area of western China are taken as an example. A total of 197 frac hits well events in this area are systematically classified via the frac-hit discrimination method, and the effects of different factors on HF- and NF- dominated frac hits are classified and studied. Combined with the correlation analysis method and the chart method, the main controlling factors affecting the two types of frac hits are determined, and the corresponding frac-hit prevention countermeasures are proposed. The research demonstrates that (1) the distribution and development of NFs are crucial to production after frac hits. NFs and HFs in the WY area cause 51% and 49%, respectively, of the frac hits. (2) The main controlling factors in NF-dominated frac hits are the approximation angle, fracture linear density, and horizontal stress difference, whereas they are net pressure in fractures, horizontal stress difference, and liquid strength in HF-dominated frac hits. Sensitivity analysis shows that the NF activation difficulty coefficient fluctuates between −35.1% and 47.6%, and the maximum hydraulic fracture length fluctuates between −43.5% and 25.29%. (3) The corresponding frac-hit prevention countermeasures are proposed for the two types of formation mechanisms from different approaches, including frac-hit risk assessment and path planning, production well pressurization and stress diversion, and infill-well fracturing parameter optimization. This paper not only provides a reference for exploring the formation mechanism of frac hits in fractured shale gas reservoirs but also a theoretical basis for the corresponding frac-hit prevention countermeasures.

Multi-stage and multi-well fracturing and induced stress evaluation: An experiment study

Multi-stage and multi-well fracturing of horizontal wells are indispensable techniques in developing shale oil and gas. Increasing the stimulated reservoir volume (SRV) is of vital importance for production. However, further research is still required due to the uncertainty of fracture propagation mechanism and the evolution of induced stress. To date, there are few true triaxial hydraulic fracturing physical simulations of large-natural shale samples. By using 13 cubic shale samples (30 × 30 × 30 cm), we investigated the effect of in-situ stress, treatment parameters, and different patterns of multi-well fracturing (staggered or tip-to-tip) on fracture propagation. The pumping pressure data is collected, and the evolution data of the induced stress is measured by a strain gauge which is glued on the rock surface. The fracture geometry is analyzed based on post-fracturing reconstruction, the fracturing data, and the induced stress evolution data. Finally, the suggestions for improving multi-stage and multi-well fracturing treatment are proposed. The results show that: A low overburden stress makes the bedding plane easier to be opened, and it also stops the main hydraulic fracture propagating to the deep reservoir. A high injection rate generates higher net pressure in fracture, and the hydraulic fracture can propagate and cross the bedding plane easily. While using a low injection rate, the liquid can only leak along the bedding plane near the wellbore, leading to a simple fracture geometry. The more fracturing stages, the more complex the fracture network is, and the induced stress data shows an obvious increase. The addition of temporary plugging agent causes a significant increase in pumping pressure and induced stress curves, and the fracture geometry is more complex. Compared with the experiment that has no temporary plugging agent, the induced stress has an increase of 0.7 MPa. In multi-well fracturing experiments, the type of multi-well fracturing (staggered or tip-to-tip) plays an important role on fracture propagation: The fracture complexity in tip-to-tip pattern is significantly lower than that in fracturing staggered pattern because of the “frac-hit”. The longer time interval between treating two wells, the lower the induced stress and the more regular fracture geometry. Further, the fractures that generated in the first well will be reopened by the fluid from the second well when the “frac-connection” occurs between the two wells, causing the induced stress to rise again. The results may provide a reference for the multi-stage and multi-well fracturing design.

Twenty-Two Years of GPS Monitoring at Rabaul Caldera, a Narrative History

It has long been recognised that volcanoes deform as fluids migrate, or change pressure in fractures and reservoirs within the volcano or in the crust below and around them. Calderas in particular have been shown to deform in complex and often major ways. The Rabaul Caldera is a type example of a caldera that undergoes complex and occasionally rapid deformation. This was first recognised by visual observations, and by the 1970s these movements were being monitored by traditional surveying techniques. Between 1972 and 1994, the centre of the caldera was uplifted by approximately 2 m. Following the 1994 eruption, it was indirectly found that parts of the caldera were uplifted ~6 m in the final hours before the eruption. It was realized that ‘real-time’ monitoring of the uplift may have given a better warning that an eruption was imminent. Traditional surveying techniques are time consuming; in the late 1990s, the only option for real-time monitoring was a Global Positioning System (GPS). By early 2000, a real-time GPS system was working at Rabaul Volcanological Observatory (RVO). Twenty-two years of continually recording differential GPS or Global Navigational Satellite System (GNSS) has proven the technique to be of immense importance. Often it has been the only parameter showing that unrest is happening. At times, inflation and deflation have warned of impending activity or recorded the emptying of the system; at other times, patterns of deformation have been more difficult to interpret. The technique has proven its worth in monitoring the status or general ‘health’ of the caldera, but for more precise forecasts it can only form part of an integrated monitoring system. Current testing of much cheaper receivers and improvements in telemetry mean the technique may soon be available for the more remote volcanoes of Papua New Guinea.

An online generalized multiscale approximation of the multipoint flux mixed finite element method

In this paper, we develop an online generalized multiscale approximation of the multipoint flux mixed finite element method (MFMFE) for Darcy flow in highly heterogeneous porous media, which can handle full tensor permeability fields and unstructured grids with local velocity elimination. Here, for illustration of the proposed method, we will mainly consider the situation that the porous medium is filled with fractures, which usually results in unstructured grids, and the extension to the situation that the permeability is represented as a full tensor is straightforward. From the fine-grid discretization by the MFMFE method, we derive the symmetric and positive definite discrete bilinear form for both the matrix and fracture pressure, and thereby obtain the corresponding discrete weak formulation that only related to pressure. In the offline stage, we compute offline basis functions which contain the important local multiscale information of each coarse-grid block to form the initial multiscale space. In the online stage, we construct and add online basis functions to enrich the multiscale space and consequently improve the accuracy of the multiscale solution. Each offline basis function and each online basis function contains multiscale information both for matrix and fracture. We give the theoretical analysis for the convergence of the online enrichment, which shows that more sufficient initial basis functions lead to faster convergence rates. A series of numerical examples that either the permeability is a full tensor or the porous medium is filled with fractures are presented to show the performance of the multiscale method.