Optimization of shut-in time based on saturation rebalancing in volume-fractured tight oil reservoirs

Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing.

Implication of Water-Rock Interaction for Enhancing Shale Gas Production

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,acidsensitive 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.

Shut-in time optimization after fracturing in shale oil reservoirs

A multi-process(fracturing,shut-in and production)multi-phase flow model was derived considering the osmotic pressure,membrane effect,elastic energy and capillary force,to determine the optimal shut-in time after multi-cluster staged hydraulic fracturing in shale reservoirs for the maximum production.The accuracy of the model was verified by using production data and commercial software.Based on this model and method,a physical model was made based on the inversion of fracture parameters from fracturing pressure data,to simulate the dynamic changes of pore pressure and oil saturation during fracturing,soaking and production,examine effects of 7 factors on the optimal shut-in time,and find out the main factors affecting the optimal shut-in time through orthogonal experiments.With the increase of shut-in time,the increment of cumulative production increases rapidly first and then tended to a stable value,and the shut-in time corresponding to the inflection point of the change was the optimal shut-in time.The optimal shut-in time has a nonlinear negative correlation with matrix permeability,porosity,capillary pressure multiple and fracture length,a nonlinear positive correlation with the membrane efficiency and total volume of injected fluid,and a nearly linear positive correlation with displacement.The seven factors in descending order of influence degree on optimal shut-in time are total volume of injected fluid,capillary force multiple,matrix permeability,porosity,membrane efficiency,salinity of fracturing fluid,fracturing fluid displacement.

A pressure drop model of post-fracturing shut-in considering the effect of fracturing-fluid imbibition and oil replacement

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 hori-zontal wells and understanding the oil-water exchange law of shale reservoir after fracturing.

Effects of instantaneous shut-in of high production gas well on fluid flow in tubing

As the classical transient flow model cannot simulate the water hammer effect of gas well, a transient flow mathematical model of multiphase flow gas well is established based on the mechanism of water hammer effect and the theory of multiphase flow. With this model, the transient flow of gas well can be simulated by segmenting the curved part of tubing and calculating numerical solution with the method of characteristic curve. The results show that the higher the opening coefficient of the valve when closed, the larger the peak value of the wellhead pressure, the more gentle the pressure fluctuation, and the less obvious the pressure mutation area will be. On the premise of not exceeding the maximum shut-in pressure of the tubing, adopting large opening coefficient can reduce the impact of the pressure wave. The higher the cross-section liquid holdup, the greater the pressure wave speed, and the shorter the propagation period will be. The larger the liquid holdup, the larger the variation range of pressure, and the greater the pressure will be. In actual production, the production parameters can be adjusted to get the appropriate liquid holdup, control the magnitude and range of fluctuation pressure, and reduce the impact of water hammer effect. When the valve closing time increases, the maximum fluctuating pressure value of the wellhead decreases, the time of pressure peak delays, and the pressure mutation area gradually disappears. The shorter the valve closing time, the faster the pressure wave propagates. Case simulation proves that the transient flow model of gas well can optimize the reasonable valve opening coefficient and valve closing time, reduce the harm of water hammer impact on the wellhead device and tubing, and ensure the integrity of the wellbore.

Mechanism and prevention method of drill string uplift during shut-in after overflow in an ultra-deep well

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.

Geothermal Investigations in Permafrost Regions—The Duration of Temperature Monitoring after Wellbores Shut-In

The most important data on the thermal regime of the Earth’s interior come from temperature measurements in deep boreholes. The drilling process greatly alters the temperature field of formations surrounding the wellbore. In permafrost regions, due to thawing of the formation surrounding the wellbore during drilling, representative data can be obtained only by repeated observations over a long period of time (up to 10 years). Usually a number of temperature logs (3 - 10) are taken after the well’s shut-in. Significant expenses (manpower, transportation) are required to monitor the temperature regime of deep wells. In this paper we show that in most of the cases (when the time of refreezing formations is less than the shut-in time) two temperature logs are sufficient to predict formations temperatures during shut-in, to determine the geothermal gradients, and to evaluate the thickness of the permafrost zone. Thus the cost of monitoring the temperature regime of deep wells after shut-in can be drastically reduced. A simple method to process field data (for the well sections below and above the permafrost base) is presented. Temperature logs conducted in two wells were used to demonstrate utilization of this method.

Field Method Research for Leak-off Coefficient Analysis Using Instantaneous Shut-in Pressure

The accurate monitor and prediction of fracturing pressure for formation is very important to hydraulic fracturing treatment operation, but whether hydraulic fracturing is successful or not, the fracturing fluid plays a very important role, leak-off coefficient is the most leading parameters of fracturing fluids. Mini-frac test was the most commonly used tools for leak-off coefficient analysis, but it has the shortcoming of time-consuming and costly that can not meet the requirement of the production. The main purpose of this paper is to introduce a simple and convenient leak off coefficient analysis method with more inexpensive and time-saving than former methods. Based on ISIP （instantaneous shut-in pressure） method, a new field method of leak off coefficient field analysis model was presented. According to twice ISIP of the fracturing treatment in field operation, therefore, fluid leak off coefficient and formation characteristic can be studied quickly and reliably. More than 40 wells were fractured using this field method. The results show that average liquid rates of post-fracturing was 20 m3/d which double improvement compared with the past treatment wells. It had an important role for fracturing treatments in low permeability used in field application. reservoirs, the new model for real time analysis and adjust is successful

Numerical simulation of fracturing and imbibition in shale oil horizontal wells

The shale oil reservoir is characterized by tight lithology and ultra-low permeability,and its efficient exploitation requires the technology of multi-stage and multi-cluster hydraulic fracturing in horizontal wells and shut-in imbibition.After multi-stage and multi-cluster hydraulic fracturing,a complex fracture network is formed,and a large volume of frac fluid is stored within the fracture network.During shut-in,imbibition and exchange between oil and water occurs under the action of the capillary force and osmotic pressure,and the formation pressure builds up in the shale reservoir.On basis of the characteristics of shale oil reservoir,we establish a model of imbibition during fracturing injection and shut-in by coupling oilewater two-phase flow and saline ion diffusion in the hydraulic fractures(HFs)network,natural fractures(NFs)and matrix system under the action of capillary force and osmotic pressure.The DFN method and the multiple continuum method are introduced to characterize fluid flow between the HF and the NF and that between the NF and the matrix respectively,which avoids the problem of a large amount of computation of seepage within the complex fracture.Then,the discrete fracture network(DFN)model and the multiple continuum model are solved with the finite element method,and it is verified in flow field,saturation field and concentration field that the models are accurate and reliable.We propose the imbibition exchange volume for quantitative evaluation of the imbibition degree and a method of calculating the imbibition exchange volume.Simulation of oil and water flow in the fracturing and shut-in stages is performed based on these models.It is found that imbibition in the shale reservoir is driven by mechanisms of pressure difference,capillary force and osmotic pressure.The osmotic pressure and capillary force only cause an increase in the imbibition rate and a reduction in the imbibition equilibrium time and do not lead to variation in the peak of imbibition exchange volume.The imbibition equilibrium time under the action of the capillary force and osmotic pressure is reduced from 150 to 45 d compared with that under the action of the pressure difference.If imbibition equilibrium is reached,low initial water saturation,strong rock compressibility,high formation water salinity and high matrix permeability enhance imbibition and exchange of oil and water in the reservoir.The leakoff volume of frac fluid is generally larger than the imbibition exchanged volume.Leakoff equilibrium occurs slightly earlier than imbibition equilibrium.The imbibition equilibrium time is mainly affected by reservoir permeability and NF density.The number of interconnected fractures mainly affects the frac fluid volume within the hydraulic fracture in the fracturing process.The stimulated reservoir volume(SRV)mainly affects frac fluid imbibition exchange in the shut-in process.

“硬关井”水击压力计算及其应用

根据气侵后环空气液两相流分布特点及水击压力在气液两相流及单相流中传播特点，计算了“硬关井”情况下的水击压力变化情况。研究表明：对于气侵情况，硬关井引起的水击压力对井眼中下部影响很小，主要作用于井口装置；如果并口流速不太大，可以采用硬关并，以便减少地层流体进一步侵入。

Enhancing economic sustainability in mature oil fields:Insights from the clustering approach to select candidate wells for extended shut-in

Fluctuations in oil prices adversely affect decision making situations in which performance forecasting must be combined with realistic price forecasts.In periods of significant price drops,companies may consider extended duration of well shut-ins(i.e.temporarily stopping oil production)for economic reasons.For example,prices during the early days of the Covid-19 pandemic forced operators to consider shutting in all or some of their active wells.In the case of partial shut-in,selection of candidate wells may evolve as a challenging decision problem considering the uncertainties involved.In this study,a mature oil field with a long(50+years)production history with 170+wells is considered.Reservoirs with similar conditions face many challenges related to economic sustainability such as frequent maintenance requirements and low production rates.We aimed to solve this decision-making problem through unsupervised machine learning.Average reservoir characteristics at well locations,well production performance statistics and well locations are used as potential features that could characterize similarities and differences among wells.While reservoir characteristics are measured at well locations for the purpose of describing the subsurface reservoir,well performance consists of volumetric rates and pressures,which are frequently measured during oil production.After a multivariate data analysis that explored correlations among parameters,clustering algorithms were used to identify groups of wells that are similar with respect to aforementioned features.Using the field’s reservoir simulation model,scenarios of shutting in different groups of wells were simulated.Forecasted reservoir performance for three years was used for economic evaluation that assumed an oil price drop to$30/bbl for 6,12 or 18 months.Results of economic analysis were analyzed to identify which group(s)of wells should have been shut-in by also considering the sensitivity to different price levels.It was observed that wells can be characterized in the 3-cluster case as low,medium and high performance wells.Analyzing the forecasting scenarios showed that shutting in all or high-and medium-performance wells altogether results in better economic outcomes.The results were most sensitive to the number of active wells and the oil price during the high-price period.This study demonstrated the effectiveness of unsupervised machine learning in well classification for operational decision making purposes.Operating companies may use this approach for improved decision making to select wells for extended shut-in during low oil-price periods.This approach would lead to cost savings especially in mature fields with low-profit margins.

Interactions between the Design and Operation of Shale Gas Networks, Including CO_2 Sequestration

As the demand for energy continues to increase, shale gas, as an unconventional source of methane(CH_4), shows great potential for commercialization. However, due to the ultra-low permeability of shale gas reservoirs, special procedures such as horizontal drilling, hydraulic fracturing, periodic well shut-in, and carbon dioxide(CO_2) injection may be required in order to boost gas production, maximize economic benefits, and ensure safe and environmentally sound operation. Although intensive research is devoted to this emerging technology, many researchers have studied shale gas design and operational decisions only in isolation. In fact, these decisions are highly interactive and should be considered simultaneously. Therefore, the research question addressed in this study includes interactions between design and operational decisions. In this paper, we first establish a full-physics model for a shale gas reservoir. Next, we conduct a sensitivity analysis of important design and operational decisions such as well length, well arrangement, number of fractures, fracture distance, CO_2 injection rate, and shut-in scheduling in order to gain in-depth insights into the complex behavior of shale gas networks. The results suggest that the case with the highest shale gas production may not necessarily be the most profitable design; and that drilling, fracturing, and CO_2 injection have great impacts on the economic viability of this technology. In particular, due to the high costs, enhanced gas recovery(EGR) using CO_2 does not appear to be commercially competitive, unless tax abatements or subsidies are available for CO_2 sequestration. It was also found that the interactions between design and operational decisions are significant and that these decisions should be optimized simultaneously.

Comparative study of well soaking timing(pre vs.post flowback)for water blockage removal from matrix-fracture interface

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 matrixfracture 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.,postflowback)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.

A prediction method of natural gas hydrate formation in deepwater gas well and its application

To prevent the deposition of natural gas hydrate in deepwater gas well,the hydrate formation area in wellbore must be predicted.Herein,by comparing four prediction methods of temperature in pipe with field data and comparing five prediction methods of hydrate formation with experiment data,a method based on OLGA&PVTsim for predicting the hydrate formation area in wellbore was proposed.Meanwhile,The hydrate formation under the conditions of steady production,throttling and shut-in was predicted by using this method based on a well data in the South China Sea.The results indicate that the hydrate formation area decreases with the increase of gas production,inhibitor concentrations and the thickness of insulation materials and increases with the increase of thermal conductivity of insulation materials and shutdown time.Throttling effect causes a plunge in temperature and pressure in wellbore,thus leading to an increase of hydrate formation area.