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Horizontal well drilling and multi-stage hydraulic fracturing technologies are at the root of commercial shale gas development and exploitation. During these processes, typically, a large amount of working fluid enters the formation, resulting in widespread water-rock interaction. Deeply understanding such effects is required to optimize the production system. In this study, the mechanisms of water-rock interaction and the associated responses of shale fabric are systematically reviewed for working fluids such as neutral fluids, acid fluids, alkali fluids and oxidative fluids. It is shown that shale is generally rich in water-sensitive components such as clay minerals, acid-sensitive components (like carbonate minerals), alkali-sensitive components (like quartz), oxidative-sensitive components (like organic matter and pyrite), which easily lead to change of rock fabric and mechanical properties owing to water-rock interaction. According to the results, oxidizing acid fluids and oxidizing fracturing fluids should be used to enhance shale gas recovery. This study also indicates that an aspect playing an important role in increasing cumulative gas production is the optimization of the maximum shut-in time based on the change point of the wellhead pressure drop rate. Another important influential factor to be considered is the control of the wellhead pressure considering the stress sensitivity and creep characteristics of the fracture network. [ABSTRACT FROM AUTHOR]

The aqueous fluid (water) is accumulated near the interfaces between fractures (hydraulic and natural) and the matrix during hydraulic fracturing. The accumulated water can be partially removed either through the immediate well flow back or through shutting in well before the flow back. Which method is more effective for oil recovery? The answers are mixed in the literature from field reports and experimental or simulation studies. This article proposes a hypothesis that the flow back of fracturing fluid is controlled mainly by two mechanisms: viscous displacement and capillary imbibition. The shut-in can outperform the immediate flow, or vice versa, depending on reservoir and operation conditions. When the viscous displacement dominates, the immediate flow back is more effective. When the capillary imbibition dominates, the shut-in is more effective. The hypothesis is verified by the results of many simulation models which are built by modifying some parameters of the same base model. Those parameters include pressure drawdown, capillary pressure, matrix permeability, wettability, initial water saturation, and formation compressibility. It is implied from this study that the immediate flow back is preferred to the shut-in method if the capillary pressure is small; otherwise, the shut-in is preferred. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

One investigates the post-shut-in growth of a plane-strain hydraulic fracture in an impermeable medium while accounting for the possible presence of a fluid lag. After the stop of fluid injection, the fracture may present three distinct propagation patterns: an immediate arrest, a temporary arrest with delayed propagation, and a continuous fracture growth. These three patterns are all followed by a final fracture arrest yet the fracture behaviour prior to that results from the interplay between the dimensionless toughness K m , the shut-in time t s / t om , and the propagation time t / t s . K m characterizes the energy dissipation ratio between fracture surface creation and viscous fluid flow under constant rate injection. t s and t om represent respectively the timescale of shut-in and the coalescence of the fluid and fracture fronts. The immediate arrest occurs when the fracture toughness dominates the fracture growth at the stop of injection ( K m ⪆ 4.3 ). It may also occur upon an early shut-in at low dimensionless toughness associated with an overshoot of fracture extension and a significant fluid lag. For intermediate values of K m and t s / t om , the fracture may experience a temporary arrest followed by a restart of fracture propagation. The period of the temporary arrest becomes shorter with higher dimensionless toughness and later shut-in until it drops to zero. The fracture behaviour after shut-in then transitions from temporary arrest to continuous propagation. These propagation patterns result in different evolution of fracture dimensions which possibly explains the various emplacement scaling relations reported in magmatic dikes. Highlights: Transitional pulse solutions for plane-strain hydraulic fractures with zero lag Immediate fracture front arrest upon shut-in associated with an overshoot of fracture extension Temporary fracture arrest and step-wise fracture growth after shut-in in the presence of a fluid lag [ABSTRACT FROM AUTHOR]

Oxidizing stimulation of organic-rich shale reservoirs, as a supplement of hydraulic fracturing, was proposed to enhance shale gas recovery. Previous publications revealed that the interaction between organic-rich shale and oxidative fluids causes the components' dissolution, which induces lots of pores and microfractures, resulting in rock microfracturing without confined pressure and associated increments of the matrix permeability, and improving unpropped fracture conductivity. However, the enhancement of shale gas recovery with oxidative fluids still lacks an implementation clue targeted for specific engineering problems. In recent years, water–rock interaction inducing microfractures indicates a positive effect of retained fracturing fluid on the stimulation after the fracturing operation, which sheds light in the enhancement of shale gas production by shut-in. The objectives of this study are to provide a new perspective whereby the shut-in performance to enhance shale gas recovery could be increased by the injection of oxidative fluids into the formation during the fracturing operation. Firstly, the mechanisms of shut-in performance increased by oxidative dissolution, which illustrate the increment of the density of fracture networks, the improvement of fracture network conductivity, and the promotion of gas desorption and diffusivity, are demonstrated. Then, the feasibility of using oxidative fluids to increase shut-in performance, which follows the geological and engineering characteristics of organic-rich shale reservoirs, is evaluated. Finally, according to the analysis of production performance for two typical types of shale gas wells, in which one is a low gas production and a high fracturing fluid recovery (LGP-HFR) and the other is a high gas production and a low fracturing fluid recovery (HGP-LFR), a shut-in strategy with oxidative fluids to enhance shale gas recovery is developed. This indicates that the injection of oxidative fluids during the fracturing operation may become a promising and cost-effective approach to enhance shale gas recovery. [ABSTRACT FROM AUTHOR]

Since the production regime of shut-in after fracturing is generally adopted for wells in shale oil reservoir, a shut-in pressure drop model coupling wellbore-fracture network-reservoir oil-water two-phase flow has been proposed. The model takes into account the effects of wellbore afterflow, fracture network channeling, and matrix imbibition and oil exchange after stop of pumping. The simulated log-log curve of pressure-drop derivative by the model presents W-shape, reflecting the oil-water displacement law between wellbore, fracture network and matrix, and is divided into eight main control flow stages according to the soaking time. In the initial stage of pressure drop, the afterflow dominates; in the early stage, the pressure drop is controlled by the cross-flow and leakoff of the fracture system, and the fractures close gradually; in the middle stage of pressure drop, matrix imbibition and oil exchange take dominance, and the fracturing fluid loss basically balances with oil replaced from matrix; the late stage of pressure drop is the reservoir boundary control stage, and the leakoff rate of fracturing-fluid and oil exchange rate decrease synchronously till zero. Finally, the fracture network parameters such as half-length of main fracture, main fracture conductivity and secondary fracture density were inversed by fitting the pressure drop data of five wells in Jimsar shale oil reservoir, and the water imbibition volume of matrix and the oil replacement volume in fracture were calculated by this model. The study results provide a theoretical basis for comprehensively evaluating the fracturing effect of shale oil horizontal wells and understanding the oil-water exchange law of shale reservoir after fracturing.

Compared with conventional reservoirs, shale reservoirs are more difficult to develop due to their characteristics of self-generation and self-storage and tightness. Based on the experience accumulated in production practice, the technical method of improving shale oil development through shut-in is put forward. The literature research on shale reservoirs shows that there is a lack of microscopic study on imbibition, the essence of oil–water exchange is not clear enough, and there is a lack of the systematic summary and induction of theoretical knowledge. This article starts from the background of shut-in stimulation of Gulong shale oil, conducts literature research on the related knowledge of shut-in of shale oil from three aspects: characterization of fracture network, shut-in mechanism, and oil and water distribution state, and summarizes the law of shut-in of shale oil in a microscopic aspect. On this basis, a dual-porosity numerical simulation model is established according to the geological and fluid characteristics of the Gulong shale oil reservoir. Through the simulation of a numerical simulation model, the water saturation and pressure maps of the matrix and lamellation-fracture system in the process of shut-in were obtained. It was found that the matrix system basically did not participate in the oil–water exchange in the process of shut-in, so in the subsequent characteristic curve analysis, only the lamellation-fracture system was mapped and analyzed. The water saturation and pressure curves of different distances of the main fracture at different times were made, and it was found that the water saturation and pressure in the main fracture and near fracture areas were higher, and the change was more obvious than that in the far. Thus, the pressure drop curves of the near fracture were used to analyze the flow stage of the fluid. The single variable method is used to analyze the influencing factors from two aspects: the fracture density and permeability of the stimulated zone. The results will give a better understanding of the oil and water distribution during shut-in and guide the duration of shut-in in shale oil reservoirs.

Oxidizing stimulation of organic-rich shale reservoirs, as a supplement of hydraulic fracturing, was proposed to enhance shale gas recovery. Previous publications revealed that the interaction between organic-rich shale and oxidative fluids causes the components’ dissolution, which induces lots of pores and microfractures, resulting in rock microfracturing without confined pressure and associated increments of the matrix permeability, and improving unpropped fracture conductivity. However, the enhancement of shale gas recovery with oxidative fluids still lacks an implementation clue targeted for specific engineering problems. In recent years, water–rock interaction inducing microfractures indicates a positive effect of retained fracturing fluid on the stimulation after the fracturing operation, which sheds light in the enhancement of shale gas production by shut-in. The objectives of this study are to provide a new perspective whereby the shut-in performance to enhance shale gas recovery could be increased by the injection of oxidative fluids into the formation during the fracturing operation. Firstly, the mechanisms of shut-in performance increased by oxidative dissolution, which illustrate the increment of the density of fracture networks, the improvement of fracture network conductivity, and the promotion of gas desorption and diffusivity, are demonstrated. Then, the feasibility of using oxidative fluids to increase shut-in performance, which follows the geological and engineering characteristics of organic-rich shale reservoirs, is evaluated. Finally, according to the analysis of production performance for two typical types of shale gas wells, in which one is a low gas production and a high fracturing fluid recovery (LGP-HFR) and the other is a high gas production and a low fracturing fluid recovery (HGP-LFR), a shut-in strategy with oxidative fluids to enhance shale gas recovery is developed. This indicates that the injection of oxidative fluids during the fracturing operation may become a promising and cost-effective approach to enhance shale gas recovery.

Water blockage after hydraulic fracturing is one of the major challenges in shale oil recovery which affects the optimal production from the reservoir. The water blockage represents a higher water saturation near the matrix-fracture interface, which decreases the hydrocarbon relative permeability. The removal of water blockage in the field is typically carried out by soaking the well (i.e., shut-in) after hydraulic fracturing operation is finished. This soaking period allows water redistribution, which decreases the water saturation near the matrix-fracture interface. However, previous field reports show that there is not a strong consensus on whether shut-in is beneficial in terms of production rate or ultimate oil recovery. Due to the large number of parameters involved in hydraulic fracturing and tight formations, it is challenging to select which parameter plays the dominant role in determining the shut-in performance. Furthermore, literature on field case studies does not frequently report the parameters which are of researchers’ interest. In other words, the challenge of evaluating shut-in performance not only lies on the complexity of parameters and effects involved within the reservoir, but also the limited number of field case studies which report a comprehensive list of fracturing and reservoir parameters.This paper aims to investigate the effect of well soaking timing on shut-in performance. This idea to investigate the shut-in timing effect is motivated by the fact that in the field, shut-in can take place either immediately after hydraulic fracturing but before the first flowback (i.e., pre-flowback) or sometime after the first flowback (i.e., post-flowback). The timing of shut-in is believed to influence the production performance, because it dictates how much water is allowed to imbibe from the fractures to the matrix before the extended production. A numerical model is built and validated by a successful history match with numerous data from core-flood experiments. Our previous study shows that shut-in performance depends heavily on the desiccation state of the formation: in non-desiccated formations, longer shut-in (pre-flowback) results in a lower regained hydrocarbon relative permeability, but in desiccated formations, longer shut-in (pre-flowback) does not affect the regained hydrocarbon relative permeability.In this study, our model further demonstrates that shut-in performed after the first flowback (i.e., post-flowback) can help ensure a higher regained oil relative permeability than shut-in performed before the first flowback (i.e., pre-flowback) in such non-desiccated formations. A mechanistic analysis on the water blockage mitigation from these two shut-in timings is also presented. As a result, this study proposes that flowback should be carried out immediately following hydraulic fracturing, even if an extended shut-in is to be performed later.

With the continuous development of the petroleum resources, unconventional oil reservoirs such as shale oil and tight oil have gradually become a main development direction of oil reservoirs in various countries. The reserves of shale oil in China are huge, reaching 1.42 × 1011 t; therefore, China has a great development potential and prospects for exploitation. However, in the process of developing shale oil reservoirs, we encountered many problems, such as un-replenishment of formation pressure and low flowback rate. At this stage, the development technology of shale oil reservoirs cannot effectively solve these problems. The proposition of shut-in technology can effectively improve these problems in theory, but the current shut-in technology of shale reservoirs after fracturing in China is still in its infancy. There is no in-depth understanding of the mechanism of shut-in wells. In addition, the factors affecting the change of oil-water distribution during shut-in after fracturing are complex, mainly including reservoir permeability, capillary force, fracture stress sensitivity, and reservoir damage. This paper investigates the mechanism of shut-in in shale reservoirs after fracturing and summarizes the mechanism of the shut-in process. Then, a single well shut-in numerical simulation model is established for the three complex characteristics of spontaneous imbibition, fracture stress sensitivity, and reservoir damage, and the oil-water distribution and change laws of shut-in shale reservoirs after fracturing are analyzed. Finally, the numerical model is used to study the influence of reservoir permeability, capillary force, fracture stress sensitivity, and reservoir damage on oil-water replacement, pressure increase, and daily fluid production during shut-in. The research results show that the influence of reservoir permeability and capillary force is more obvious, and the influence of fracture stress sensitivity and reservoir damage is relatively small.

• Arrest radius of a hydraulic fracture after injection shut-in. • Numerical delineation of a boundary for immediate arrest upon shut-in. • Numerical quantification of the amount of post-injection propagation. • Semi-analytical solution for a pulse hydraulic fracture in the viscosity regime. We investigate the propagation and arrest of a radial hydraulic fracture upon the end of the injection. Depending on the regime of propagation at the time of shut-in of the injection, excess elastic energy may be stored in the surrounding medium. Once the injection has stopped, the hydraulic fracture will arrest when the energy release rate falls under the material fracture energy. Fluid leaking-off to the surrounding medium acts as an energy sink such that the available excess energy for fracture growth decreases faster and as a result impacts the arrest (actually controls it in the zero toughness limit). Under the assumption of a homogeneous elastic medium and the Carter's leak-off model, we show that the post shut-in propagation of the hydraulic fracture depends on the dimensionless toughness K s and leak-off C s coefficient at the time of shut-in. Our investigation highlights that for an impermeable rock, the arrest radius is independent of the dimensionless toughness at shut-in. In the limit of a permeable rock with zero fracture toughness, the arrest radius is independent of the dimensionless leak-off coefficient only for C s < 0.25. For larger values of C s , the radius of arrest reduces with increasing C s . We delineate the limit above which the arrest is immediate upon shut-in. This limit is given by a critical leak-off coefficient at shut-in C s , c ≈ 0.53 for the large leak-off/small toughness cases and by the relation C s , c K s , c ≈ 0.78 - 0.313 · K s , c for small leak-off/large toughness (where K s , c is equivalently the critical dimensionless toughness at shut-in). Immediate arrest in the impermeable limit is observed for K s , c ≈ 2.5. If both ( K s and C s ) are smaller than their critical value for immediate arrest, post shut-in propagation occurs and a self-similar pulse viscosity storage solution emerges. Scaling arguments combined with numerical simulations, show that the propagation post shut-in scales as 1.23 K s - 2 / 5 in the impermeable and small leak-off cases, and as 0.75 C s - 2 / 13 in the zero toughness limit. The growth post shut-in can be significant in impermeable rocks - with a final radius up to twice larger than the radius at shut-in for realistic material and injection parameters. [ABSTRACT FROM AUTHOR]

During hydraulic fracturing, thousands of barrels of fluid are injected into the rock surrounding the created fractures. Observations show that later during flowback, only a small fraction of the injected fluid volume is produced back. In tight naturally fractured formations, this can be explained by the leading role of preexisting rock discontinuities in the transport of fluids in such rocks. In this work, we investigate the mechanics of injected fluid flow in and out of preexisting rock discontinuities during a typical operational sequence of fracturing treatment, well shut-in and flowback. The mechanics of fluid flow in compliant discontinuities, where conductivity is sensitive to stress changes, is different from that in a stiff rock matrix. To understand and quantify rock pressurization, fluid leakoff and flowback rates, we develop a numerical model of fluid flow in a system of arbitrarily oriented discontinuities. Using this model, we predict spatial distribution of the injected fluid in a naturally fractured rock at any time after the beginning of the fracturing treatment as well as after the well shut-in and during flowback. The model explains the trapping of injected fluid in the discontinuities during production. We validate the model by comparison with field data and provide rough estimates of the volumetric fracturing fluid accumulation in the rock discontinuities after the treatment. The spatial extent of rock "flooding" around hydraulic fractures is found to depend on the density and orientation of rock discontinuities. [ABSTRACT FROM AUTHOR]

Copyright of China Petroleum Machinery is the property of China Petroleum Machinery Editorial Department and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Among investigations on the mechanics of energy accumulation via well shut-in to increase oil production, reservoir imbibition is deemed effective. However, another element, i.e., the coupling effect of fluid flow and geomechanics has always been underrated in production. Hence, this is discussed herein based on seepage mechanics, elastic mechanics, and Biot pore elastic theory. Further, an integral mechanical coupling numerical model is established from staged fracturing on a horizontal well to analyze well shut-in and production, to simulate stress variation during the shut-in period and the impact of shut-in time on oil production. The model considers the coupling effect of oil and water flow, and geomechanics on the stress distribution of reservoir adjacent to hydraulic cracks during fracturing, well shut-in, and production. From the study of reservoir stress and physical parameters in different shut-down times, it is found that reservoir stress and physical parameters demonstrate some regular changes. The pore pressure and saturation demonstrate pressure diffusion and oil phase saturation recovery with increasing well shut-in time. Owing to pressure diffusion, horizontal maximum principal stress, and horizontal minimum principal stress, the shear stress and stress difference demonstrate high complexity. Meanwhile, permeability and porosity exhibit a complex distribution subject to effective stress; the characteristic parameters of reservoir rock based on construction parameters (total injection volume, injection rate, and shut-in time) affect the subsequent production considerably. The correlation curves drawn upon a simulated experiment that reflect the construction parameters against cumulative oil production indicate that cumulative oil production is in direct proportion to shut-in time and in reverse proportion to injection rate. The optimum shut-in time is correlated positively with both the total injection volume and injection rate. • A shut-in model is established to study the relationship between shut-in time and construction parameter. • Induced stress and fluid-solid coupling during fracturing and shut-in were considered. • Our conclusion can provide some guidance for field operation and theory. [ABSTRACT FROM AUTHOR]

Abstract Water blockage is a type of formation damage that occurs because of capillary discontinuity at the interface between high-capillarity matrix and low-capillarity fracture. This water blockage causes a reduction in oil relative permeability and the need for higher drawdown to allow flowback after hydraulic fracturing. To remove this blockage, shut-in is believed to be effective because it dissipates the water blockage from the matrix-fracture interface deeper into the matrix through capillary imbibition. However, field data demonstrates mixed results – Some field data report shut-in as beneficial, whereas others detrimental. This paper investigates desiccation as one of the main reasons for the mixed shut-in implications. From the perspective of multiphase flow in porous media, our history-matched core-scale model reveals that shut-in can offer some benefits in desiccated water-wet cores but cause further damage in non-desiccated ones. Regardless of the desiccation, our simulation results show that immediate flowback can help ensure high oil relative permeability and remove the trapped water at the matrix-fracture interface more quickly. In a desiccated core, both immediate flowback and shut-in result in the same maximum regained oil relative permeability; however, in a non-desiccated core, immediate flowback results in a higher maximum regained oil relative permeability than shut-in. [ABSTRACT FROM AUTHOR]

Abstract Drill string will sustain large uplift force during the shut-in period after gas overflow in an ultra-deep well, and in serious case, it will run out of the wellhead. A calculation model of uplift force was established to analyze dynamic change characteristics of the uplift force of drill string during the shut-in period, and then a management procedure for the uplift risk during the shut-in period after gas overflow in the ultra-deep well was formed. Cross section method and pressure area method were used to analyze the force on drill string after shut-in of well, it was found that the source of uplift force was the "fictitious force" caused by the hydrostatic pressure in the well. When the fictitious force is in the opposite direction to the gravity, it is the uplift force. By adopting the theory of annular multiphase flow, considering the effects of wellbore afterflow and gas slippage, the dynamic change of the pressure and fluid in the wellbore and the uplift force of drill string during the shut-in period were analyzed. The magnitude and direction of uplift force are related to the length of drill string in the wellbore and shut-in time, and there is the risk of uplift of drill string when the length of drill string in the wellbore is smaller than the critical drill string length or the shut in time exceeds the critical shut in time. A set of treatment method and process to prevent the uplift of drill string is advanced during the shut-in period after overflow in the ultra-deep well, which makes the risk management of the drill string uplift in the ultra-deep well more rigorous and scientific. [ABSTRACT FROM AUTHOR]

The objective of this study is to develop a technique to identify the optimum water-soaking time for maximizing productivity of shale gas and oil wells. Based on the lab observation of cracks formed in shale core samples under simulated water-soaking conditions, shale cracking was found to dominate the water-soaking process in multi-fractured gas/oil wells. An analytical model was derived from the principle of capillary-viscous force balance to describe the dynamic process of crack propagation in shale gas formations during water-soaking. Result of model analysis shows that the formation of cracks contributes to improving well inflow performance, while the cracks also draw fracturing fluid from the hydraulic fractures and reduce fracture width, and consequently lower well inflow performance. The tradeoff between the crack development and fracture closure allows for an optimum water-soaking time, which will maximize well productivity. Reducing viscosity of fracturing fluid will speed up the optimum water-soaking time, while lowering the water-shale interfacial tension will delay the optimum water-soaking time. It is recommended that real-time shut-in pressure data are measured and shale core samples are tested to predict the density of cracks under fluid-soaking conditions before using the crack propagation model. This work provides a shut-in pressure data-driven method for water-soaking time optimization in shale gas wells for maximizing well productivity and gas recovery factor.

Interacting with the pre-existing natural fractures, multi-stage hydraulic fracturing along with long horizontal well creates complex fracture networks in gas-shale reservoirs. Field data indicate that only a small fraction of the hugely injected fracturing fluid can be recovered during the clean-up period, especially when the well undergo an extended shut-in period. Therefore, it is essential to investigate the interaction between the non-recovered fluid and the fracture to understand the behavior of fluid-loss and production performance. A series of mechanistic simulation models consisting of hydraulic fracture (HF) and natural/secondary fracture (NF) were constructed to simulate imbibition, fluid re-distribution, and flowback during well shut-in and cleanup periods. Firstly, the established 3-D model system was used to investigate the impact of shut-in immediately after the production and a certain period of flowback. Furthermore, sensitivity analysis was subsequently performed with corresponding stochastic 2-D model, which systematically quantified the impact of fracture uncertainties in 1) fracture complexity and, 2) fracture distribution. The results indicate that, after incorporated with the imbibition hysteresis, water saturation of fracture is close to 1 even if the well has been shut in for a long period before flowback, and the saturation increases with the extending of shut-in during flowback. In addition, the rate fluid imbibition into the reservoir is extremely slow, and the invasion depth is less than 3 m after 100 days’ shut-in. It is also concluded that shut-in duration is not proportional to gas production when we divide the shut-in situation into two cases. Therefore, it is inappropriate to judge that the longer the shut-in period is, the more favorable the production will be. For the fracture networks, we linked the density of NF with the half-length of HF to investigate the fracture complexities. The results show that more complicated fracture will greatly enhance gas production and reduce water recovery efficiency (flowback rate). Finally, different distribution patterns have different impact on well performance, but, the overall influence is much less than that of complexity. [ABSTRACT FROM AUTHOR]

This article is designed for the application of Cocamidopropyl hydroxyl sulfobetaine (CHSB) in the nitrogen foam flooding under the high-temperature and high-salinity environments. Firstly, foam properties of CHSB were evaluated at different temperatures and varying salinity, as well as the effect of concentration on foam properties, and the long-term foam properties of CHSB were developed under different concentration. Then, a series of researches on controlling mobility of nitrogen foam were conducted in the sand-packs. Finally, nitrogen foam flooding was carried out in the sand-model and oilfield site. Results indicated that high-temperature was unfavorable to foam stability, and high-salinity could favor its stability. When CHSB was used as foaming agent at the concentration of 0.2 wt%, it showed excellent performance at the temperature of 120 °C and the salinity of 22×10 4 mg/L and good long-term stability after aging for 60 days. The foam flooding experiments showed that mobility reduction factor of foam increased with the residual oil saturation decreased or as the permeability declined in the high-temperature and high-salinity, and the residual resistance factor of foam during the subsequent waterflooding with 5 days shut-in was 3.8, which was obviously higher than that without shut-in or with shut-in in oil-free environment. The displaced area in sand-model was lager and wider in the presence of 5 days’ shut-in than that in the absence of shut-in, and the water cut could be reduced to 38% and the enhanced oil recovery was about 17.8% after 5 days’ shut-in. The oilfield test showed that the validity period of high oil production rate was more than half year and 2400 t of crude oil was produced in all. [ABSTRACT FROM AUTHOR]

A Web-Based Computer System (RPM-WEBBSYS) has been developed for the application of the Rational Polynomial Method (RPM) to estimate static formation temperatures (SFT) of geothermal and petroleum wells. The system is also capable to reproduce the full thermal recovery processes occurred during the well completion. RPM-WEBBSYS has been programmed using advances of the information technology to perform more efficiently computations of SFT. RPM-WEBBSYS may be friendly and rapidly executed by using any computing device (e.g., personal computers and portable computing devices such as tablets or smartphones) with Internet access and a web browser. The computer system was validated using bottomhole temperature (BHT) measurements logged in a synthetic heat transfer experiment, where a good matching between predicted and true SFT was achieved. RPM-WEBBSYS was finally applied to BHT logs collected from well drilling and shut-in operations, where the typical problems of the under- and over-estimation of the SFT (exhibited by most of the existing analytical methods) were effectively corrected. [ABSTRACT FROM AUTHOR]

The evolution of fractures during shut-in after hydraulic fracturing is an important topic in petroleum engineering. Considering the closure and secondary expansion of fractures during shut-in can further improve the accuracy of predicting hydraulic fracture parameters. Based on linear elastic fracture mechanics, elastic mechanics, and the implicit level set algorithm, a numerical model of planar hydraulic fracture propagation was established in this study. In the proposed model, the reservoir was considered as a homogeneous elastic medium, and the fluid loss was characterized using Carter's filtration model. The secondary propagation and fracture closure behavior during shut-in could be simulated by solving the strongly nonlinear system of fluid and stress coupling. Based on this model, the evolution behavior of hydraulic fractures during injection and shut-in was analyzed. According to the variation characteristics of the fracture length, the evolution process could be divided into three stages: fracture propagation during injection, secondary growth, and fracture stopping (but not closing). According to the variation characteristics of the fracture opening and net pressure, the evolution process could be divided into three stages: nonlinear increase, linear decrease, and gradual decrease. For low-permeability reservoirs, fracture closure and secondary propagation may take several times the injection time after shut-in, and the secondary propagation length may reach tens of meters. The results show that the larger the filtration coefficient, the faster the fracture closure will be, and the shorter the secondary propagation distance. The higher the viscosity of the fracturing fluid, the slower the fracture closure will be, while the secondary propagation distance is almost unaffected. The fracture toughness has little effect on the fracture closure and secondary propagation. The crack will close first in the region with large interlayer stress during shut-in. The findings of this study can help for better understanding of the evolution mechanism of fractures during shut-in and closure. • A three-dimensional planar hydraulic fracture model is established. • Fracture secondary propagation during shut-in is considered. • Fracture closure behavior is considered during shut-in. • The level set factor algorithm is used to solve the injection and shut-in models. • The influence of filtration, influence strength factor, viscosity on fracture evolution is analyzed. [ABSTRACT FROM AUTHOR]

Shale gas wells often experience shut-in. However, the positive and negative effects of shut-in are not yet clear. The success or failure of shut-in is focused on the effects of fracturing fluid and its function in the subsurface. The current studies on the hydration of shale and fracturing fluid and the imbibition of residual fracturing fluids have ignored the fact that hydration and imbibition of fracturing fluids can occur simultaneously and affect each other. With full consideration of the interaction between the spontaneous imbibition and hydration of fracturing fluid, this paper innovatively reveals the fracture initiation through the synergy of spontaneous imbibition and hydration of residual fracturing fluids in shale gas reservoirs and puts forward suggestions for improving the recovery of shale gas. The results show that the imbibition of shale can weaken the mechanical strength of shale and produce micro-fractures and defects in shale. The energy required to destroy the micro-fractures is reduced, which will promote the initiation and propagation of micro-fractures, change the spontaneous imbibition path, expand the volume of spontaneous imbibition, and carry out continuous micro-stimulation of shale gas reservoir. The fracturing fluid can dissolve soluble salts filled in the pores and fractures, resulting in more induced fractures along the direction of beddings and natural fractures. The induced fracture reduces the water saturation of the hydraulic fractures and natural fractures. The fluid in pores can disperse under the action of capillary force, which can further reduce the water saturation of the imbibition intrusion zone, thus greatly restoring the permeability of the shale gas reservoir. • The synergy of spontaneous imbibition and hydration of fluid is revealed. • The imbibition depth of fracturing fluids during shut-in is revealed. • The positive and negative effects of shut-in of shale gas well is revealed. • The mechanism of self-relieving of water trapping during shut-in is revealed. [ABSTRACT FROM AUTHOR]

Liquid loading is a common problem for most of the mature gas wells. Over years, many methods have been developed to solve this problem. One of the widely used methods is plunger lift, which requires shut-in of the gas well for a period of time. Then, the well is reopened, and it is expected that the natural energy of the well will push the plunger to the surface carrying the liquid with it. Optimization of the plunger lift requires that the well be shut-in for a period of time as short as possible, followed by production of gas for as long as possible. This note examines the requirement for a successful shut-in of a well so that the well can sustain the production for a longer time. The note also discusses the condition under which the well will not sustain the production and the plunger lift will not be effective. The analysis is confirmed with several field examples, which will be shown in this note. [ABSTRACT FROM AUTHOR]

CO 2 phase transition and fluid interaction in the wellbore-reservoir system after shut-in are two critical phenomena, which are crucial to predicting the long-term fate of CO 2 in a deep saline aquifer storage project. In this study, a wellbore-reservoir coupled numerical model is developed based on the Shenhua Ordos Carbon Capture and Storage (CCS) project in China. This model can cope with the CO 2 phase transition and is designed to investigate fluid behavior during the non-injection period. The simulation results show that the liquid-phase CO 2 above a depth of ∼300 m within the wellbore will transit to the gas phase during the non-injection period. The changes in the pressure and temperature associated with the phase transition are too small to be a safety hazard. Moreover, the injected CO 2 will flow back to the wellbore and even flow into the top injection layer with the maximum permeability during the non-injection period; for a sufficiently long non-injection period, the formation water will also flow back. This process may redistribute the injected CO 2 in the multi-layered reservoir. The parameter sensitivity analysis indicates that the permeability distribution of the reservoir has the most profound effect on the reservoir backflow process. These results provide an in-depth understanding of the fluid behavior within the wellbore-reservoir system after shut-in and offer theoretical guidelines for similar CCS project operations. • CO 2 phase change and fluid backflow from reservoir to well after shut-in are modeled. • Liquid-phase CO 2 in the upper wellbore gasifies after shut-in. • The two-phase zone in the upper wellbore shows oscillation characteristic. • The injected CO 2 flows back into the wellbore and into other layers after shut-in. • The reservoir permeability has a profound effect on the fluid backflow process. [ABSTRACT FROM AUTHOR]

Induced seismicity in geothermal projects is observed to continue after shut-in of the fluid injection. Recent experiments show that the largest events tend to occur after the termination of injection. We use a probabilistic approach based on Omori's law and the Gutenberg-Richter magnitude-frequency distribution to demonstrate that the probability of exceeding a certain maximum magnitude still increases after shut-in. This increase is governed by the exponent of Omori's law q and the Gutenberg-Richter b value. For a reduced b value in the post-injection phase, the probability of occurrence directly after shut-in can be even higher than the corresponding probability for an ongoing injection. For the reference case of q = 2 and a 10% probability at shut-in time t to exceed a given maximum magnitude, we obtain an increase to 14.6% for t = 2 t at a constant Gutenberg-Richter b value after shut-in. A reduction of the b value by one quarter leads to a probability of 20.5%. If we consider a constant probability level of occurrence for an event larger than a given magnitude at shut-in time, this maximum magnitude increases by 0.12 units for t = 2 t (0.26 units for a reduced b value). For the Soultz-sous-Forêts (France) injection experiment in 2000, recent studies reveal q = 9.5 and a b value reduction by 14%. A magnitude 2.3 event 9 h after shut-in falls in the phase with a probability higher than for the continued injection. The probability of exceeding the magnitude of this post-injection event is determined to 97.1%. [ABSTRACT FROM AUTHOR]

The paper presents a multi-objective evolutionary algorithm applied to history matching of waterflooding projects, which is to search a feasible set of geological properties showing the reliable future performance. Typical history matching has concentrated on single objective function with linearly weighted terms, even as a realistic field includes many wells and well measurements in time and type. The optimal solution is sensitive to weight factor and competing match criteria of individual term in the objective function often reduce the likelihood of finding an acceptable match. The unacceptable error at a specified well can be observed in a heterogeneous reservoir where shows nonlinear well performances. To overcome the inaccuracy, a new history matching approach is developed that allows the performance characteristics of the whole wells. Individual well performance is optimized separately using genetic algorithm coupled with non-dominated sorting and diversity preservation. The fitness is sorted along to the proximity and then the diversity is added by examining the crowding distance as the approach to arrive at the global optimum. Waterflooding is demonstrated in a heterogeneous oil reservoir with multiple production wells. The predictability of unknown future production performance is compared with that of single objective function, the conventional history matching method. The model represents individualized well-performance more accurately than the conventional history matching. It improves a certainty of the conventional model by showing small error range. The selection of adequate set of reservoir properties is possible among the feasible solutions unlike the conventional model. The developed method can be applied as a useful tool for uncertainty analyses in waterflooding projects. [ABSTRACT FROM AUTHOR]

Abstract: A strategy based on proportional-integral (PI) feedback control was applied to solve an inverse heat transfer problem for estimating static formation temperatures (SFTs) from logged temperatures in oil wells. The PI control feedbacks the error between logged and simulated temperatures during the shut-in time process, existing SFT proposal. Thus, mathematically speaking an inverse heat transfer problem was solved in this way, since SFT represents the initial conditions (which are unknown) to solve the partial differential equations governing the heat transfer process in the wellbore-formation system. The mathematical model considers transient convective heat transfer due to circulation losses to the rock surrounding a well. The methodology was tested analyzing two oil wells (MB-3007 and MB-3009) from the Gulf of Mexico and results were compared against two classic methods. The method presented in this work needs only one temperature measurement for each fixed depth to estimate the SFT. [Copyright &y& Elsevier]

• Hydrate formation under transient conditions is studied using a rock-flow cell. • Shear applied at restart contributes to hydrate breakup. • High subcooling in a low water cut system promotes the dry-hydrate formation. • If hydrates already exist, a shut-in/restart will not change the state of the system. In offshore oil production, scheduled or emergency shutdowns of the production system may occur due to maintenance, equipment failure, production issues, and weather-related events. During the shut-in, the fluids may enter into the hydrate zone because of the thermal energy transfer to the cold ocean waters, increasing the risk of hydrate formation during the shut-in period and upon the restart of the production system. This work is focused on identifying some parameters that influence the hydrate formation in shut-in and restart conditions. Using a rock-flow cell with visual capabilities, the hydrate formation and the phenomena involved upon the restart were investigated. The main results of the experiments showed that the high shear conditions applied at the restart promoted water dispersion into the oil phase and contributed to the dispersion of hydrates. In addition, the low shear rate favored the formation of hydrate deposits while hydrate agglomerate was formed at high shear rate. Besides the shear rate, the subcooling proved to be an important parameter that favors the hydrate formation under sheared conditions. Conditions with high subcooling and low water cut promoted the formation of small hydrate particles (~2 mm) that can be dispersed in the oil-phase even without the anti-agglomerant. A high subcooling promoted the formation of "dry" hydrates, preventing the particles to stick with each other (agglomerates). The results indicated that subcooling is an important parameter to ensure a safe restart in the pipeline. Lastly, the addition of an anti-agglomerant reduced the water–oil interfacial tension, which promoted the water/hydrate dispersion; the effectiveness of the anti-agglomerant was clearly affected by the shear and the water cut. [ABSTRACT FROM AUTHOR]

This paper presents a feedback-based strategy to solve an inverse heat transfer problem for the estimation of unperturbed formation temperatures (UFT) from measured temperatures in wellbores. The feedback function uses the error between the measured and estimated temperatures during the shut-in process. Thus, an inverse heat transfer problem was solved in this way since the UFT represents the unknown initial conditions and the measured temperatures in the wellbore represents the particular solution of the PDE’S governing the heat transfer process in the formation and in the wellbore system. The performance of the method is illustrated via numerical simulations of two wells: (a) oil well FE-1227 from the Gulf of Mexico maritime zone and (b) well CP-0512 from Cerro Prieto Mexican geothermal field. [Copyright &y& Elsevier]

Water soaking a horizontal shale well is a practice whereby operators in shale gas and oil production shut-in a well after a multistage hydraulic fracture treatment. By this practice, it is expected that production volumes will increase when the well is eventually opened to flow. However, there is currently no consensus on the benefits derived from this procedure. This is due to limited understanding of the subsurface mechanisms during the soaking period and their effect on both short- and long-term productivity. Also, the duration of soaking is currently chosen arbitrarily. This study reviews a decade of research (2010–2020 including January–February of 2021) in the subject area. Focus is placed on subsurface mechanisms during soaking, the fate of water-based hydraulic fracture fluids, and production performance of wells which have experienced soaking. Models describing production performance from soaking are presented and compared. It became evident from the reviewed works that the performance of soaking is affected by several factors of which soaking duration and water imbibition are the most significant. These factors can be grouped largely into fracture fluid properties, formation related parameters and operational procedures. The story of each well or field would need to be told separately when discussing soaking performace. At the same time, varying statements between operators and researchers regarding the benefits of soaking need not be considered contradictory but should be looked at on case-by-case basis. This review does not make a choice on whether to soak a well or not—it rather provides readers with research progress for the past ten years on the subject. It further narrows in on key parameters to focus on in evaluating the option to soak a well. Research directions that can contribute to the topic are also provided. • Well soaking in shale reservoirs is practiced to improve production performance. • There is currently no consensus on benefits derived from well soaking.. • Well performance with soaking is significantly affected by soaking duration and water imbibition. • The duration for soaking is currently chosen arbitrarily. • Fracture fluid properties, formation related parameters and operational procedures affect soaking performance. [ABSTRACT FROM AUTHOR]

• Two different stimulating mechanisms exist in the well shut-in process. • Oil production increases through mass transfer during shut-in. • Well shut-in is beneficial to oil production in low pressure and low-perm reservoirs. Field data and research results regarding the effect of shut-in on oil and gas recovery performance are mixed. The stimulation mechanisms of shut-in after hydraulic fracturing are not clear in the literature. In this paper, two different types of experiments were conducted to investigate the effect of spontaneous imbibition (SI) during well shut-in process on matrix permeability and mass transfer between matrix and fractures. In the flooding-flowback experiments, changes in the oil production rate before and after shut-in were used to characterize the regained permeability variation. Amott cells were used in the spontaneous imbibition experiments to measure the oil recovered by the mass transfer effect. The results indicate that water blockage in the tight reservoir is very severe, and the regained permeability is reduced by more than 75% after fracturing fluid invasion. The severity increases as the core matrix become tighter, and the pressure drawdown is set to be lower. After shut-in, the initial permeability did not recover but decreased. To describe the shut-in process more accurately, we divided the well shut-in into early and late stages. In the early stage, fracturing fluid invades the rock matrix, further reducing the permeability, and oil is recovered through the counter-current flow. The results indicate that well shut-in is not favorable to oil production with higher permeability or higher formation pressure. In the later stage, with less fracturing fluid remains in the fractures, the enhancement of hydrocarbon production is mainly caused by fracturing fluid redistribution in the low-permeable matrix. [ABSTRACT FROM AUTHOR]

The estimation of temperatures in and around a geothermal well during circulation, and during shut-in conditions in the presence of lost circulation is presented in this work. Estimated temperatures are compared with temperature logs measured during drilling stoppages. Temperatures were estimatted using a computer code specifically developed to account for the transient convective heat transfer due to lost circulation in the rock surrounding a well. This feature of the present code is important since wellbore simulators normally consider the heat transfer process in the rock as a merely conductive problem. The code is capable of accounting for these losses at any point in the well and application was made to the study of two Mexican geothermal wells(well LV-3 from the Las Tres Vírgenes field and well EAZ-2 from the Los Azufres field). The results show that the effect of lost circulation on the shut-in temperature profiles can be modelled satisfactorily. Research is under way to improve the present methodology. [ABSTRACT FROM AUTHOR]

The instantaneous shut-in of the gas well produces a transient flow phenomenon. The repeated pressure amplitude and pressure repeated changes will cause the vibration of the tubing and equipment, resulting in damage to tubing and accessory equipment. However, it is difficult to directly adopt the conventional transient flow model due to the particularity environment of the gas well bore. Based on the classical transient flow theory and mechanism of transient flow process in a gas well, a mathematical model explaining the transient flow phenomenon of gas well is established and the method of characteristics is adopted for numerical solution. The calculation results of sample show that, after the wellhead valve is closed instantaneously, the surge pressure is transmitted and gradually attenuates under the influence of frictional resistance, and reaches the balance pressure after a period of time. With the increase of valve closure time, the maximum value of wellhead pressure is reduced, and the time of peak value occurs is also delayed. When the gas well is shut in for a short time, the propagation speed of pressure wave is faster than that in the circumstance of shutting the gas well in a longer time. The transient flow model can accurately reflect the value of surge pressure, the cycle of surge pressure and attenuation law of pressure wave, which has a high reference value for studying the transient process and pressure distribution in the gas well bore. • This paper establishes a multi-phase transient flow model of gas wells. • The mathematical model is solved by the characteristic line method. • The propagation of pressure wave with well depth is obtained. • This paper analyses the influence of valve closure time on transient flow process. [ABSTRACT FROM AUTHOR]

Relative permeability is one of the most important parameters in reservoir modeling. However, measurements of relative permeability in unconventional reservoir rocks are rare, and the influence of relative permeability hysteresis on reservoir studies has not previously been addressed. This paper presents a systematic investigation of gas-water relative permeability and hysteresis based on a laboratory technique developed through our previous work. Gas relative permeability was measured using the modified gas expansion method under the scenario of drainage and subsequent imbibition. Water relative permeability was estimated based on Brooks-Corey (1956) equations. Results of gas-water relative permeability that cover a broader range of saturation than that in our previous work were obtained. Causes of relative permeability hysteresis are discussed in detail. The laboratory-based gas-water relative permeability of one of the samples is compared to history-matched results from the literature, and upscaling of the laboratory result is discussed on the basis of this comparison. Finally, the potential influence of relative permeability hysteresis on water and gas production after hydraulic fracturing and shut-in is illustrated through a conceptual model and quantitative analysis. Gas production rates can be overestimated after hydraulic fracturing when hysteresis is ignored. Shut-in can enhance gas production rates significantly. Enhancement of production rate is greater at the initial phase, but it diminishes later, after continuous expansion of the imbibition zone. This work presents the first known study of gas-water relative permeability hysteresis in unconventional reservoir rocks. • The first study of hysteresis of gas-water relative permeability in shale. • Causes of relative permeability hysteresis is discussed. • Laboratory-based results are comparable to that from history-matching in literature. • Hysteresis and shut-in have significant impacts on gas production. • The impacts of hysteresis and shut-in on water-production are minor. [ABSTRACT FROM AUTHOR]

• A model is proposed to predict the hydrate deposition for deep-water gas wells under shut-in condition. • The deep-water wellbore environment after shut-in is divided into transient stage and steady stage. • The hydrate formation region and thickness distribution at different shut-in time can be analyzed by the model. • This work is beneficial to optimize conventional strategy of hydrate management under shut-in conditions. Natural gas hydrate is one of the major issues in the development of deep-water oil and gas industry. The shut-in operation increases the risk of hydrate formation under higher pressure and lower temperature conditions. Conventional hydrate prevention methods may inject excessive amount of inhibitors, which leads to additional cost and environmental pollution. There are few studies on quantitative prediction of hydrate formation and deposition after deep-water shut-in. In this paper, a prediction model of hydrate deposition considering water vapor condensation and liquefaction for deep-water gas well under shut-in conditions is established. The deposition model is divided into transient and steady stage based on the variation characteristics of temperature. During the process of hydrate formation after shut-in operation, the consumption amount of free water is used as the verification parameter in this paper, and the average error between the experimental results and the simulations is 11.75%. The simulations suggest that the amount of hydrate deposition will increase as the shut-in time increase and the initial temperature raise along with the change of production parameters, but the overall deposition amount is small. Furthermore, especially in the short-term shut-in operations for deep-water gas wells, the low rate of water vapor diffusion and liquidation causes a small amount of deposited hydrate, which is not serious enough to cause blockage issues. The simulation results changed the conventional prevention recognition and it is helpful to decrease the cost of hydrate management. This study can serve as useful suggestions for the design and optimization for deep-water gas wells under shut-in conditions. [ABSTRACT FROM AUTHOR]

The objective of this study is to develop a technique to identify the optimum water-soaking time for maximizing productivity of shale gas and oil wells. Based on the lab observation of cracks formed in shale core samples under simulated water-soaking conditions, shale cracking was found to dominate the water-soaking process in multi-fractured gas/oil wells. An analytical model was derived from the principle of capillary-viscous force balance to describe the dynamic process of crack propagation in shale gas formations during water-soaking. Result of model analysis shows that the formation of cracks contributes to improving well inflow performance, while the cracks also draw fracturing fluid from the hydraulic fractures and reduce fracture width, and consequently lower well inflow performance. The tradeoff between the crack development and fracture closure allows for an optimum water-soaking time, which will maximize well productivity. Reducing viscosity of fracturing fluid will speed up the optimum water-soaking time, while lowering the water-shale interfacial tension will delay the optimum water-soaking time. It is recommended that real-time shut-in pressure data are measured and shale core samples are tested to predict the density of cracks under fluid-soaking conditions before using the crack propagation model. This work provides a shut-in pressure data-driven method for water-soaking time optimization in shale gas wells for maximizing well productivity and gas recovery factor. [ABSTRACT FROM AUTHOR]

When stimulated only by natural energy, tight oil reservoirs have low production efficiency. Improving the potential for oil recovery by imbibition is essential to enhancing oil production. Shut-in is an effective way to make good use of the potential for oil recovery by imbibition. In this study, imbibition experiments and nuclear magnetic resonance (NMR) testing were combined to reveal the characteristics of spontaneous imbibition and the T 2 value of the oil recovery potential by imbibition in tight oil reservoirs. The main factors affecting the potential for oil recovery by imbibition were studied. We also discussed the relationship between clay minerals and the potential for oil recovery by imbibition, especially the time-delay effect of imbibition displacement. A modified model based on the static balance time for spontaneous imbibition was proposed to calculate the field shut-in time. The results show that the static spontaneous imbibition balance time of tight oil reservoirs are significantly different in various zones. The oil recovery by imbibition has an obvious time-delay effect and it could put the oil in non-movable pores under natural conditions to use. Internal conditions like microscopic pore structure and the type of clay minerals affect the oil recovery by imbibition on small pores (T 2 < 100 ms). External conditions like reservoir temperature, pressure, and bedding affect oil recovery by imbibition in small and large pores. The clay minerals expand after the interaction between fracturing fluids and rock. Meanwhile, oil is discharged with compression of those pore space. To optimize the shut-in time of a tight reservoir, these effects of clay behavior can suggest good practices in hydraulic fracturing. • The characteristics of imbibition and the law of oil displacement by imbibition were fully revealed at the macroscopic and microscopic scale. • The time-delay effect in the progress of imbibition displacement is proposed for the first time. [ABSTRACT FROM AUTHOR]