Shut-in Stage Research Articles

Wettability evaluation of shale oil reservoirs and its impact on the post-fracturing shut-in duration of horizontal wells: a quantitative study for Ordos Basin, NW China

Shale oil development in Ordos Basin, China, primarily relies on the displacement of crude oil during the post-fracturing shut-in stage (PFSIS) of horizontal wells. Reservoir wettability significantly influences the shut-in duration and even the development approach. However, due to strong heterogeneity and super tight characteristics, the reservoir usually shows an mixed wettability, and it was usually hard to differentiate the wettability in different pore sizes. With this in mind, this study focuses on core samples from shale oil reservoir in the Longdong region of the Ordos basin to quantitatively analyze the reservoir wettability. Amott method combined with nuclear magnetic resonance is adopted in the paper to meed this end. And the optimal post-fracturing shut-in duration for Huachi and Heshui areas in the Longdong region are determined based on both wettability and field practice analysis as well as numerical simulations. Qualitative wettability evaluation reveals that the reservoir in the Longdong region is weakly oil-wet (oil-wet pores account for 58.9% and water-wet pores for 41.1%), and that larger pores are more water-wet, while smaller pores are more oil-wet. Field practice observes a noticeable two-stage decline in wellhead pressure, with pressure drop rates and water content decline rates following the order of neutral reservoir > weakly oil-wet reservoir > oil-wet reservoir during the post-fracturing shut-in stage. Numerical simulations indicate that the determination of the optimal post-fracturing shut-in duration for horizontal wells should consider reservoir properties, wettability, and injection volume. The final optimal shut-in durations for the Huachi and Heshui areas in the reservoir are determined to be 36 days and 43 days, respectively. Our study qualitatively distinguishes the wettability in different pores sizes and thus determines reasonable post-fracturing shut-in durations in different areas in Longdong region. The research has major implication for building a realistic method of wettability analysis in shale or tight oil reservoir.

Numerical investigation of the stress regime effect on injection-induced fault reactivation and associated seismicity

The occurrence of many seismic events in energy production projects is caused by fluid injection-induced reactivation of critically stressed faults. The distribution of local stress regime has a significant influence on natural earthquakes, while its role in controlling injection-induced fault slip behavior and seismicity magnitude remains poorly understood. In this paper, we present a three-dimensional hydro-mechanical coupled fault reactivation study using unified pipe-interface element method (UP-IEM). The accuracy and reliability of the numerical method are evaluated and confirmed by numerical verification and actual observation data in Pohang EGS project, South Korea. The relationship between fault aseismic slip, seismic slip and seismicity magnitude is analyzed. Results show that both aseismic and seismic slip have different spatiotemporal distribution with the variation of stress regime. The seismic slip zone will exceed the pressurized area with the increase of initial slip tendency under the strike-slip-faulting stress regime (σH>σv>σh). Compared with fluid pressure, the seismic slip is mainly determined by a sudden increase of the shear stress at the aseismic slip zone boundary. In addition, the location of the microseismic events moves towards the fluid pressure propagation front. The larger slip area and seismicity magnitude are easier to be induced under strike-slip-faulting stress regime than thrust-faulting stress regime (σH>σh>σv). The tensile failure and higher permeability of the fault induced at injection phase for normal-faulting stress regime (σv>σH>σh) leads to a greater seismogenic hazard at the shut-in stage.

An integrated approach to investigating the stimulation mechanisms of soaking in shale/tight oil reservoirs

To investigate the impact of the soaking strategy on the entire shut-in, flowback, and production processes following hydraulic fracturing, we developed a core simulation system using nuclear magnetic resonance technology to track fluid migration across the entire process. This simulation system, with a specially designed core sample, enabled us to quantify the contribution of each stage to oil production and analyze the stimulation mechanism of soaking from an integrated perspective. Our results demonstrate that forced imbibition during the shut-in stage includes both countercurrent imbibition and cocurrent displacement. Increasing the pressure difference between the fracture and matrix strengthens the displacement effect and weakens the imbibition effect, leading to decreased oil recovery. In contrast, from an integrated perspective, increasing the pressure difference can enhance total oil recovery. This is because two additional stimulation mechanisms of soaking, namely, oil–water redistribution and formation pressure enhancement, can be observed only during the subsequent flowback and production stages and not during the shut-in period. As the pressure difference increases, the main stimulation mechanism of soaking changes from countercurrent imbibition to oil–water redistribution and formation pressure enhancement. Additionally, we observed that the soaking strategy can cause severe water blockage, hindering the full utilization of the formation pressure enhancement mechanism. This study reveals that the stimulation mechanisms in the shut-in stage have a wide-ranging impact that extends beyond this stage. Therefore, adopting an integrated approach is necessary to study the stimulation mechanism of soaking, breaking the traditional view of analyzing a single stage alone.

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 oil–water 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.

Experimental study on hydraulic fracture propagation in heterogeneous glutenite rock

To understand the fracture behavior and discuss the possibility of the reservoir-stimulated volume concept on glutenite rock, true triaxial hydraulic fracturing experiments were performed on glutenite rocks with acoustic emission monitoring. Experimental results indicate that a curved hydraulic fracture (HF) can be created. In addition, in situ stress plays the greatest role in HF propagation direction regardless of gravel characteristics; however, the gravel with high mechanical strength could affect hydraulic fracture path locally. Intense fluctuate extension pressure and discrete surged acoustic emission (AE) events not only occur during the breakdown stage but also during the shut-in stage, indicating embedded gravels tend to influence HF process. The breakdown pressure is the highest for sample with low horizontal stress difference, while breakdown pressure for large-size sample with small gravel numbers is the lowest. The highest AE amplitude can be observed for sample where fracture positions on gravels are at the initial stage, while continuous high AE amplitude is observed for samples with high pump rates during the entire process, indicating intense fracture and gravel interactions. Moreover, four possible interaction behaviors between HF and gravels, namely, fracture penetration, deflection, diversion and arrest, can be identified near wellbore and far-field failure zones. In general, fracture penetration behavior is exclusively observed within the near wellbore failure zone. Additionally, the fracture width for a penetration fracture is the largest due to high fracturing energy, while fracture diversion and arrest exhibit the smallest fracture width. Given the existence of gravels, branch fractures are difficult to merge with residual fracturing energy. An extremely coarse HF surface and tortuous HF path can be found for all samples; thus, the selection of a suitable pump rate and fracturing fluid is necessary to migrate near wellbore tortuosity.

On the Stability of Particle–Particle Interaction during Gravitational Settling

The elevated energy demand and high dependency on fossil fuels have directed researchers’ attention to promoting and advancing hydraulic fracturing (HF) operations for a sustainable energy future. Even though previous studies have demonstrated that the proppant suspension and positioning in slickwater play a vital role during the shut-in stage of the HF operations, minimal experimental work has been conducted on the fundamental proppant–proppant interaction mechanisms, especially a complete mapping of the interactions. This study utilizes high-speed imaging to provide a 2D space- and time-resolved investigation of two-particle (proppant models: 2 mm Ø, 2.6 g·cm−3) interactions during gravitational settling in different initial spatial configurations and rheological properties. The mapping facilitates the identification of various interaction regimes and newly observed particle trajectories. Pure water results at a settling particle Reynolds number (Rep) ~ 470 show an unstable particle–particle interaction regime characterized by randomness while altering pure water to a 25% (v/v) water–glycerin mixture (Rep ~ 200) transitions an unstable interaction to a stable prominent repulsion regime where particles’ final separation distance can extend up to four times the initial distance. This indicates the existence of Rep at which the stability of the interactions is achieved. The quantified trajectories indicate that when particles are within minimal proximity, a direct relation between repulsion and Rep exists with varying repulsion characteristics. This was determined by observing unique bottle-shaped trajectories in the prominent repulsion regimes and further highlighted by investigating the rate of lateral separation distance and velocity characteristics. Additionally, a threshold distance in which the particles do not interact (or negligibly interact) and settle independently seems to exist at the normalized 2D lateral separation distance.

Application of digital rock technology for formation damage evaluation in tight sandstone reservoir

Formation damage is a common phenomenon and is impaired to the reservoir by reducing the productivity. Formation damage is usually caused by solids plugging, clay swelling, saturation changes, etc., and fracturing fluids with a series of chemical additives are pumped into the well for production enhancement. It is difficult to optimize the fracture fluids and well shut-in time due to lack of fundamental understandings. Currently, little research has been done to investigate the mechanisms of formation damage at the pore scale. In this study, a combination of digital rock technology and core sample laboratory soaking experiments is used to evaluate the formation damages for different fracture fluids in tight sandstone reservoir. Three core samples from a full-diameter core are soaked in three different fracture fluids (surfactant, polymer, and gel) for eight different durations (from 2 h to 15d) to simulate well shut-in process. The samples in various soak times are scanned by X-ray micro-computer tomography (Micro-CT) to obtain the 3D images of the true geometry. The images are then compared to optimize the fracture fluids and quantify the damage degree after various well shut-in times. Then, displacement processes are simulated using lattice Boltzmann method (LBM) to evaluate the residual oil saturations and optimize the well shut-in time. The study suggests that the well shut-in process can cause irreversible damage to tight sandstone reservoir even for optimized fracture fluid. In the initial shut-in stages, clays swelling dominates pore structure alteration and reduces the porosity. Calcite will dissolute after which lead to slight porosity increase. In the flowback process after well shut-in, the simulated residual oil saturation will decrease initially and then increase after, which is complied with the porosity variation. The digital rock technology combined with the soaking experiments will provide alternative method for the evaluation of formation damage and the optimization of well shut-in time in tight sandstone reservoir, which can guide the selection of the fracture fluids and onsite fracturing operation.

CO2–brine–rock interactions altering the mineralogical, physical, and mechanical properties of carbonate-rich shale oil reservoirs

The introduction of CO2 in deep formations triggers complex geochemical/geophysical processes, affecting CO2 geological storage safety and enhancing oil/gas recovery. Previous studies have mainly focused on the long-term geochemical reactions in reservoirs with low carbonate content (<30%). However, the short-term CO2–brine–rock interaction in carbonate-rich formations has been ignored. In this study, soaking experiments were conducted, followed by a series of multi-scale tests, to systematically quantify the mineralogical, physical, and mechanical properties of carbonate-rich shale reservoirs after CO2 fracturing and to reveal the alteration mechanisms. The results indicate that the CO2–brine–rock interaction shows a high preference for dissolving carbonate, followed by nonpure feldspars, and then pure feldspars. Carbonate may impede the dissolution of pure feldspars but has little impact on nonpure ones. With carbonate content and reaction time increases, the porosity and permeability were improved by as high as 105% and 382.1%, respectively, while the hardness, tensile strength, and toughness were weakened remarkably. Fracture closure may occur at severely softened fracture areas with a surface hardness lower than 0.07 GPa, when the reaction time lasts more than 168 h. This study implies that a long shut-in stage after CO2 fracturing in carbonate-rich shale reservoirs should be avoided.

Numerical simulation of THMC coupling temperature prediction for fractured horizontal wells in shale oil reservoir

In order to study the effects of different parameters in hydraulic fracturing on formation temperature after low-temperature fracturing fluid is injected into high-temperature reservoir, in this paper, considering (1) osmotic pressure and capillary pressure (2) microthermal effect (heat conduction, heat convection, heat expansion, viscous dissipation) (3) the coupling processes of temperature (T), hydraulic, (H) mechanical (M) and chemical (C) in hydraulic fracturing process, and the coupled temperature prediction model of oil-water two-phase THMC based on discrete fractures is established. The effects of fracturing fluid temperature, reservoir temperature, dimensionless conductivity, Young's modulus, injection rate, cluster spacing, and proportion of branch fracture area on reservoir and fracture temperature during the pumping and shut-in stages of shale oil reservoir were studied. The results show (1) For formations with different reservoir temperatures, the temperature drop at the fracture was approximately 97% from the start of the operation to the end of the 30-day shut-in. The saturation change caused by fracturing fluid filtration is much larger than the temperature change caused by heat transfer, and it is found that the temperature and saturation change mainly occur in the early shut-in period (2) Imbibition accelerates the filtration loss of fracturing fluid. During pumping, the bottom hole temperature with imbibition considered is lower than that without imbibition considered. The temperature curve with imbibition considered begins to deviate about 10 min after pumping, but the final temperature tends to be the same, (3) When the fracturing fluid is pumped at high pressure, the fracture and matrix will be deformed, which will improve the porosity and permeability of the near well zone, thus speeding up the heat transfer rate. The high Young's modulus inhibits the increase of permeability. Compared with the young's modulus of 40 GPa and 20 GPa, the increase of permeability decreases by 9% (4) When the well was shut in for 30 days, the cluster spacing was greater than 20 m, and the temperature change around the fracture did not affect the clusters on both sides. The spacing between the clusters was 5 m, and the perforation clusters on both sides had a significant effect on the temperature. The temperature of the reservoir between the two adjacent clusters dropped from 393 K to 385 K. When there is a branch fracture, the small cluster spacing is equivalent to increasing the complexity of the fracture and accelerating the initial heat transfer rate. (5) High injection temperature, high dimensionless conductivity, low Young's modulus and low pumping rate are conducive to the heat transfer of fracturing fluid in the formation.

CO2 Mass Transfer and Oil Replacement Capacity in Fractured Shale Oil Reservoirs: From Laboratory to Field

CO2-based fracturing is widely introduced to stimulate shale oil reservoirs for its multiple advantages. However, the range of CO2 entering the matrix around fractures and CO2-oil replacement capacity between matrix and fractures cannot be fully explained. To address this issue, a radial constant volume diffusion experiment on shale cores was designed in this study, and the pressure drop curve history was matched through numerical model to determine the composition effective diffusion coefficient. A field-scale numerical model was established, in which a series of certain grids were used to explicitly characterize fracture and quantify the prosess of CO2 mass transfer and oil replacement. Based on the field-scale numerical model, the process of shut-in, flow back, and oil production was simulated. The distribution of CO2 in fractured shale oil formation and its impact on crude oil during shut-in stage and flow back stage were investigated. This study concludes that CO2 gradually exchanges the oil in matrix into fractures and improve the fluidity of oil in matrix until the component concentrations of the whole reservoir reaches equilibrium during the shut-in process. Finally, about 30∼35 mole % of CO2 in fractures exchanges for oil in matrix. The range of CO2 entering the matrix around fractures is only 1.5 m, and oil in matrix beyond this distance will not be affected by CO2. During the process of flow back and production, the CO2 in fracture flows back quickly, but the CO2 in matrix is keeping dissolved in oil and will not be quickly produced. It is conclued that the longest possible shut-in time is conducive to making full use of the CO2-EOR mechanism in fractured shale oil reservoirs. However, due to the pursuit of economic value, a shut-in time of 10 days is the more suitable choice. This work can provide a better understanding of CO2 mass transfer mechanism in fractured shale oil reservoirs. It also provides a reference for the evaluation of the shut-in time and production management after CO2 fracturing.

Gradient descent algorithm to optimize the offshore scale squeeze treatments

Scale deposition is one of the serious oilfield chemical issues which may lead to a range of downhole and production problems, including the reduction of well productivity index. Scale Inhibitor (SI) squeeze treatments are one of the most common techniques which are applied to prevent downhole scaling in production wells. A treatment typically consists of four stages, (i) a preflush, to condition the rock surface; (ii) a main treatment, where a batch of high concentration inhibitor is bullheaded into the formation; (iii) an overflush, to displace the scale inhibitor slug deeper into the near-well formation, and (iv) a shut-in stage to allow further inhibitor retention before putting the well back on production. During this backflow period, scale inhibitor is released from the rock surface into the produced water, and the scale deposition is prevented if the inhibitor concentration is above some specified Minimum Inhibitor Concentration (MIC). Due to logistic constraints in offshore wells, it is often required that the scale protection afforded by a squeeze treatment should last for some fixed design lifetime until the next treatment becomes available. For example, in the North Sea sector, well operations are often based on an annual treatment design. This paper presents a methodology to optimize the squeeze treatment design for a fixed target lifetime and this is applied for two offshore well squeeze treatments. This approach allows us to account for the operational constraints in the squeeze optimization process to treat a fixed volume of produced water, while minimizing the inhibitor neat volume and the total pumping time. A sensitivity study was performed on the inhibitor concentration, where the results showed that deploying a smaller inhibitor slug but with higher concentration is more effective than a larger slug with lower concentration, assuming a fixed volume of inhibitor and injected water. Therefore, it is recommended that the inhibitor is deployed at the maximum possible concentration, while avoiding the potential for any formation damage. Considering the same inhibitor slug (volume and concentration), this study suggests that the squeeze lifetime continuously increases with the overflush volume. This implies that the lifetime function is differentiable with respect to the overflush, and thus a gradient-based optimization algorithm, specifically the Gradient Descent (GD) may be applied to find the exact overflush volume resulting in the target lifetime. Employing this procedure for a wide range of main treatment volumes allows us to calculate the squeeze “Iso-Lifetime” curve which represents all the possible squeeze designs for the target lifetime. Thereafter, from the iso-lifetime designs, the CPB value (total cost of squeeze per treated barrel of water produced) can be minimized to find the most optimum squeeze design. This approach is shown to result in the optimum scale inhibitor squeeze treatment strategy in the long-term.

Pressure-dependent flow characteristics of proppant pack systems during well shut-in and the impact of fines invasion

Near-wellbore screenouts during the shut-in stage due to the development of compact proppant clusters is an issue reported in several fracturing treatments for Coal Seam Gas (CSG) reservoirs. The usual solutions to counter this issue implemented in deep rocks such as Shale and Siltstone do not solve for coal reservoirs due to its geological characteristics. Therefore, the development of proppant packs is an expected outcome during CSG extraction, and the permeability in the proppant pack could decide the overall gas productivity. This study investigates the permeability of proppant packs prepared using the Under-compaction method to simulate compact proppant clusters experienced in near-wellbore screenouts. In this regard, two commonly used proppant types are selected; sand and ceramic, and a series of tri-axial permeability tests were conducted under various effective stresses relevant to CSG environments. According to the experimental outcomes, interestingly, both proppant packs exhibited non-Darcy and Darcy flow regimes, while the non-Darcy effect was more profound at low confining pressures due to its high packing porosity. Results showed that the permeability through the compact proppant pack depends on both the reservoir pressure and the type of proppants selected. The sand proppant pack (SPP) showed 1–2 orders higher than the permeability values of the ceramic proppant pack (CPP) until a threshold pressure is reached (10 MPa), after which the ceramic proppants produced higher permeability values. We also investigate the potential impact of the invasion of coal fines into the proppant packs and the corresponding pore blockings. The impact of fines invasion on CPP permeability was more potent compared to the fines induced SPP permeability. The shape of the ceramic particles, the polar effect of the α-Al2O3 atoms, and the attraction of the oxygen functional groups of the coal fines to these polar sites increase the likelihood of fines clogging in a ceramic proppant pack.

Cyclic Water Injection Potentially Mitigates Seismic Risks by Promoting Slow and Stable Slip of a Natural Fracture in Granite

Induced seismicity associated with fluid injection has raised serious concerns for the safety and efficiency of geo-energy systems. Cyclic injection has recently been proposed as an alternative injection scheme to reduce the large magnitude injection-induced seismicity. However, the influence of cyclic injection on the activation of natural fractures in granite and the resulting seismic risk is not yet clear. This study investigates the injection-induced activation of a critically stressed natural fracture in a granite core sample, particularly focusing on the comparison between monotonic and cyclic water injection under pressure-controlled and volume-controlled conditions. Experimental results show that the acceleration and deceleration of fracture slip are modulated by the shear stress imbalance between the fixed shear stress and the evolving frictional strength of the fracture. Fracture slip affects the fluid pressure distribution on the fracture, which in turn regulates the frictional strength of the fracture. At a small total shear displacement (i.e., ~ 0.9 mm in this study), cyclic injection with a restricted peak injection pressure results in aseismic fracture slip at much smaller peak slip rates compared to that during the monotonic injection. On the one hand, the more uniform reduction in effective normal stress caused by cyclic injection encourages slow and stable fracture slip, characterized by the smaller peak slip rates. On the other hand, the flowback of injected fluid or suspension of injection could prevent the occurrence of fast-accelerated fracture slip during cyclic injection. However, the fracture can become unstable when it has experienced a considerable amount of total shear displacement (larger than ~ 0.9 mm in this study), and likely gained a significantly enhanced permeability. Continued injection after the unstable shut-in stage, signified by an unusual increase in slip rate and an accelerated drop in injection pressure, could result in rapid and unstable fracture slip.

Fault Reactivation and Induced Seismicity During Multistage Hydraulic Fracturing: Microseismic Analysis and Geomechanical Modeling

SummaryThis paper presents a case study of fault reactivation and induced seismicity during multistage hydraulic fracturing in Sichuan Basin, China. The field microseismicity data delineate a fault activated near the toe of the horizontal well. The spatio-temporal characteristics of the microseismicity indicate that the seismic activity on the fault during the first three stages is directly related to the fluid injection, while after Stage 3, the seismic activity is possibly due to the relaxation of the fault. The fault-related events have larger magnitudes and different frequency-magnitude characteristics compared to the fracturing-related events. Three-dimensional (3D) fully coupled distinct element geomechanical modeling for the first two hydraulic fracturing stages and a shut-in stage between them is performed. The modeling result generates features of microseismicity similar to that of the field data. The energy budget analysis indicates that the aseismic deformation consumes a major part of the energy. The simulated fault shear displacement is also consistent with the casing deformation measured in the field. The model is also used to investigate the impact of possible operational changes on expected seismic responses. The results show that lower injection rate and lower fluid viscosity would be helpful in reducing casing deformation but not in mitigating seismicity. Decreasing the total fluid injection volume is an effective way to mitigate the seismicity, but it may hinder the stimulation of the reservoir formation and the production of the well.

Investigation of imbibition areas during well shut-in based on mercury injection experiment and BP neural network

Hydraulic fracturing appears to be an important and efficient method in the development of tight oil reservoirs. Well shut-in process after hydraulic fracturing enables the capillary imbibition process in leak-off area thus improving the production in tight oil reservoirs. Therefore, leak-off area is also the imbibition area. However, the range of leak-off area has not been fully understood for production engineers due to the complexity and dynamics of fracturing. In this work, we applied fractal theory to derive the matrix permeability in tight oil reservoirs, which can better describe the microscopic characteristics of reservoirs and manage the reservoir performance. Subsequently, we developed an analytical model to calculate pressure distribution at leak-off areas during the fracturing and well shut-in processes. To avoid solving nonlinear equations, we used Newton-Raphson iterative method to calculate the correlation of time and pressure. The effects of six parameters (e.g., permeability, shut-in time, viscosity, half-length of fracture and height of fracture) on the leak-off area were examined using BP neural network, and a two-dimensional distribution grid of fracturing leak-off was developed. Moreover, we computed pressure distribution of fracturing fluid leak-off area numerically to verify the reliability of the new model. Our results show that the leak-off area of fracturing fluid increases with shut-in time. Based on the BP neural network, permeability and shut-in time play significant influences in the leak-off area of fracturing fluid. This work provides insights to examine the process of hydraulic fracturing and shut-in in tight oil reservoirs, and the proposed model is a useful tool to quantify the leak-off area of fracturing fluid after shut-in stage.

Research on evaluation and prevention of hydrate formation and blockage risk in wellbore during deepwater gas wells drilling

The hydrates formation and blockage in wellbore is directly related to the safety of deepwater gas well drilling. However, the current research on hydrates risk prevention during deepwater drilling is still insufficient. In this work, a novel hydrate formation-blockage risk assessment method in wellbore is proposed. Firstly, a new hydrate formation region (HFR) prediction model consists of mass, momentum and energy balance equations was established and was verified on a deepwater gas well in South China Sea. Secondly, the wellbore blockage risk in different drilling stages is evaluated and the prediction results were in good agreement with field results. Finally, economical-effective hydrate inhibition measures are proposed to ensure the safety and efficiency of deepwater drilling. The results show that the increase of gas invasion rate, drilling fluid injection temperature and drilling fluid circulation rate are helpful to shorten HFR. In this study, the total length of HFR can be reduced by 59.26% when the gas invasion rate increases from 0 to 14 L/s, while the total HFR can be reduced to 74.93% when the drilling fluid circulation rate increases from 0.01 to 0.09 L/s. Increasing drilling fluid circulation temperature is the most direct and effective measure to reduce HFR and the HFR in annulus will disappear when drilling fluid circulation temperature rises above 36 °C. Due to the limitation of gas hydrate induction period and multi-phase flow characteristics, the wellbore plugging risk in drilling fluid circulation stage is very low, while the hydrate blockage risk in well shut-in stage is high relatively. Meantime, properly increasing drilling fluid circulation rate and injection temperature, choosing appropriate drilling balance mode during drilling fluid circulation stage, reasonable controlling the wellbore annulus pressure, optimizing shut-in time and injecting appropriate inhibitors during well shut-in stage can effectively ensure the completion of safe-economic-efficient deepwater gas wells drilling.

Automatic Optimization of Oilfield-Scale-Inhibitor Squeeze Treatments Delivered by Diving-Support Vessel

Summary Oilfield-scale deposition is one of the important flow-assurance challenges facing the oil industry. There are a number of methods to mitigate oilfield scale, such as reducing sulfates in the injected brine, reducing water flow, removing damage by using dissolvers or physically by milling or reperforating, and inhibition, which is particularly recommended if a severe risk of sulfate-scale deposition is present. Inhibition consists of injecting a chemical that prevents the deposition of scale, either by stopping nucleation or by retarding crystal growth. The inhibiting chemicals are either injected in a dedicated continuous line or bullheaded as a batch treatment into the formation, commonly known as a scale-squeeze treatment. In general, scale-squeeze treatments consist of the following stages: preflush to condition the formation or act as a buffer to displace tubing fluids; the main treatment, where the main pill of chemical is injected; overflush to displace the chemical deep into the reservoir; a shut-in stage to allow further chemical retention; and placing the well back in production. The well will be protected as long as the concentration of the chemical in the produced brine is greater than a certain threshold, commonly known as minimum inhibitor concentration (MIC). This value is usually between 1 and 20 ppm. The most important factor in a squeeze-treatment design is the squeeze lifetime, which is determined by the volume of water or days of production where the chemical-return concentration is greater than the MIC. The main purpose of this paper is to describe the automatic optimization of squeeze-treatment designs using an optimization algorithm, in particular particle-swarm optimization (PSO). The algorithm provides a number of optimal designs, which result in squeeze lifetimes close to the target. To determine the most efficient design of the optimal designs identified by the algorithm, the following objectives were considered: operational-deployment costs, chemical cost, total-injected-water volume, and squeeze-treatment lifetime. Operational-deployment costs include the support vessel, pump, and tank hire. There might not be a single design optimizing all objectives, and thus the problem becomes a multiobjective optimization. Therefore, a number of Pareto optimal solutions exist. These designs are not dominated by any other design and cannot be bettered. Calculating the Pareto is essential to identify the most efficient design (i.e., the most cost-effective design.)

Determination of transient temperature distribution inside a wellbore considering drill string assembly and casing program

Heat exchange efficiency between each region of the wellbore and formation systems is influenced by the high thermal conductivity of the drill string and casing, which further affects temperature distribution of the wellbore. Based on the energy conservation principle, the Modified Raymond, Simplified and Full-scale models were developed, which were solved by the fully implicit finite difference method. The results indicated that wellbore and formation temperatures were significantly influenced at the connection points between the drill collar and drill pipe, as well as the casing shoe. Apart from the near surface, little change was observed in temperature distribution in the cement section. In the open-hole section, the temperature rapidly decreased in the circulation stage and gradually increased in the shut-in stage. Most important, the simulated result from the full-scale model coincided with the measured field data better than the other numerical models. These findings not only confirm the effect of the drill string assembly and casing programs on the wellbore and formation temperature distribution, but also contribute to resource exploration, drilling safety and reduced drilling costs.

The influence of wettability and shut-in time on oil recovery through microscale simulation based on an ideal model

In the oil development, the most common method to enhance recovery is waterflooding. Due to different size of pores existing in reservoirs, some interesting phenomena are observed. In addition, the efficiency of waterflooding is different at different wettability. The shut-in time also has influence on the production rate after water injection while the reason is not clear. In this study, we investigate this problem with lattice Boltzmann method at pore scale, which has many advantages over pore network modeling. The effect of wettability and shut-in time are studied systematically based on an ideal pore-throat model. The whole simulation is divided into three steps: injection, shut-in and flow-back. According to the simulation, the following conclusions can be obtained. (1) In injection simulation, a better efficiency of displacement can be reached as water wettability increases, and it takes less time under weakly wetting situation. The local geometry structure has an impact on invasion order. The wetting phase intrudes into the first pore throat when it flows from pore body to pore throats. (2) In shut-in process, shut-in time has slight influence on the final water saturation, and the water saturation decreases at first, then increases with the shut-in time increasing. It takes more time for capillary pressure to be reflected in the displacement, and it depends on the number of dead end pores and the diameter and length of pore throats that connect the dead end pores. The movement of fluids is quite slow in most pores and is a dynamic balance in a few dead end pores, and the dynamic balance only happens at the beginning of shut-in stage. (3) In flow-back step, as the wettability increases, higher water saturation can be obtained after flow-back process, which leads to a better recovery. The flow-back process takes more time as the wettability decreases. The flow-back time in weakly wetting is six times more than that in highly wetting case. The distribution of oil and water is more concentrated at highly wetting situation. The remaining oil is snapped off in pore body and pore throat. As wettability decreases, the distribution of remaining oil is film-like in the pore space, and less water can invade into the dead end pore. Generally, as the wettability increases, higher recovery can be obtained. It needs take more time for the effect of shut-in to be reflected in the displacement, and even longer time for tight reservoirs.

Automatic optimization of oilfield scale inhibitor squeeze treatment designs

Squeeze treatments are one of the most common methods to prevent oilfield scale deposition, which in turn is one of the most significant flow assurance challenges in the oil industry. Squeeze treatments consist of the batch injection of a chemical scale inhibitor (SI), which above a certain concentration, commonly known as MIC (Minimum Inhibitor Concentration), prevents scale deposition. The most important factor in a squeeze treatment design is the squeeze lifetime, which is determined by the volume of water or days of production where the chemical return concentration is above MIC, which commonly is between 1 and 20ppm. Typically, squeeze treatment designs include the following four stages: a preflush, acting as a buffer; the main slug, where the main chemical slug is injected; the overflush, which will displaced the chemical pill deeper into the formation and finally, a shut-in stage, which allows the chemical to be further retained in the formation.The main purpose of this paper is to describe the automatic optimization of squeeze treatment designs using an optimization algorithm, in particular, using particle swarm optimization (PSO). The algorithm provides the optimum design for a given set of criteria that are used in a purpose built reactive transport model of the near-wellbore area. Every squeeze design is fully determined by a number of parameters; namely, injected inhibitor concentration, main slug volume, overflush volume and shut-in time. The parameter space is bound to certain limits, which will be determined by the maximum injected concentration, main slug and overflush volumes. The maximum injected concentration might be determined by, amongst other issues, logistics, economics and/or compatibility with other chemicals. The main slug and overflush maximum volumes may be identified by the well engineer based on concerns of water formation damage, hydrate formation and/or gas lifting limitations, which might be lower for high value wells. This approach still requires engineering input and review, but speeds up the process of finding an optimum design, and reduces risk of non-optimal squeeze treatments being performed.