Shut-in Time Research Articles

A semi-analytical model for simulation of multiple vertical wells with well interference

Hydraulic fracturing is widely applied to develop tight oil reservoirs, and it is significant to diagnose fracture hit to determine optimal well spacing. Pressure test is an effective method to determine fracture hit in a multi-well system. In this study, we developed a semi-analytical model to quickly identify fracture hit in multiple vertical well system in tight oil reservoir. This semi-analytical model involves several steps, i.e., prior production step of parent wells, pressure build-up step, and interference test step. The model was verified by a numerical reservoir simulator for single well and multiple wells. Then, based on the model, the well interference by fracture hit in a three-well system (two parent wells and one child well) is discussed. Results show that the developed semi-analytical model could efficiently simulate the entire production process of a multi-well system, quickly diagnose fracture hit by using pressure interference test data and determine the optimal shut-in time of parent well. The practicability of model lies in that the reservoir pressure depletion by prior production of parent wells is considered. Besides, it is found shutting down the parent well is very necessary to diagnose fracture hit when the child well is infilled. When the shut-in parent well is connected to producing child well, the pressure build-up process of parent well is terminated with the bottom hole pressure reducing continuously. What is more, the shut-in time of parent wells should be sufficient to better detect the fracture hit, especially under the condition that parent wells have produced for a long time or the connectivity among wells is weak. This work can provide critical insights into understanding the mechanism of well interference by fracture hit in a multi-well system.

Distribution and reformation characteristics of gas hydrate during hydrate dissociation by thermal stimulation and depressurization methods

Pore-scale distribution and reformation characteristics of gas hydrate in porous sediments can provide invaluable information on macroscale production behaviors. In this work, the X-ray computed tomography (X-ray -CT) has been conducted to detect distribution characteristics of the hydrate-bearing sample during hydrate formation and dissociation. Experimental results indicate that, during hydrate formation, mass and heat transfer can lead to the transformation of grain-attaching (grain-cementing and grain-contacting) hydrate to pore-filling hydrate, as well as the heterogeneous distribution of gas hydrate in pores. During hydrate dissociation, whether the thermal stimulation stage or the depressurization stage, the hydrate decomposition initiates from the ablation of the hydrate-gas interface, and the grain-cementing hydrate remains intact until the hydrate cracks into particles and collapses. In addition, during the thermal stimulation stage, the migration of “memory water” under the equilibrium hydrate formation condition leads to the hydrate reformation, and the hydrate reformation promotes the homogeneous distribution of gas hydrate in pores. During the depressurization stage, gas hydrate is reformed below the hydrate “dissociation front” because of the endothermic process of hydrate dissociation and the pressure-driven fluid flow. The reformed grain-cementing hydrate provides fluid flow channels instead of plugging the pores and throats. However, the shut-in time after the depressurization-induced gas production should not be too long to prevent the pore plugging by the further growth of the reformed hydrate. Additionally, the depressurization process finally leads to the grain migration and may reduce the sediment strength under the loose grain filling condition.

Leakoff and Flowback Experiments on Tight Carbonate Core Plugs

Summary In this paper, we investigate the change in oil effective permeability (koeff) caused by fracturing-fluid (FF) leakoff after hydraulic fracturing (HF) of tight carbonate reservoirs. We perform a series of flooding tests on core plugs with a range of porosity and permeability collected from the Midale tight carbonate formation onshore Canada to simulate FF-leakoff/flowback processes. First, we clean and saturate the plugs with reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P = 172 bar and T = 60°C). Then, we measure koeff before (baseline) and after the leakoff process to evaluate the effects of FF properties, shut-in duration, and plug properties on regained permeability values. We found that adding appropriate surfactants in FF not only significantly reduces koeff impairment caused by leakoff, but also improves koeff compared with the original baseline for a low-permeability carbonate plug. For a plug with relatively high permeability (kair > 0.13 md), freshwater leakoff reduced koeff by 55% (from 1.57 to 0.7 md) while FF (with surfactants) reduced koeff by only 10%. The observed improvement in regained koeff is primarily because of the reduction of interfacial tension (IFT) by the surfactants (from 26.07 to 5.79 mN/m). The contact-angle (CA) measurements before and after the flowback process do not show any significant wettability alteration. The results show that for plugs with kair > 0.13 md, FF leakoff reduces koeff by 5 to 10%, and this range only increases slightly by increasing the shut-in time from 3 to 14 days. However, for the plug with kair < 0.09 md, the regained permeability is even higher than the original koeff before the leakoff process. We observed 28.52 and 64.61% increase in koeff after 3- and 14-day shut-in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug, which significantly reduces irreducible water saturation (Swirr) and consequently increases koeff. Under such conditions, extending the shut-in time enhances the mixing between invaded FF and oil/brine initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results show that the regained permeability strongly depends on the permeability, pore structure, and Swirr of the plugs.

Activation and Inactivation of Seismicity: The Terminations of Two Injection Tests in Okuaizu Geothermal Field, Japan

AbstractThe injection of water into geothermal systems is an important procedure required to recover subsurface water resources and enhance permeability for increasing the reservoir volume. The injected water often leads to microseismic events during migration, which can be used to directly track the location of the injected water. However, in rare cases, unexpectedly large induced seismicity occurs after the injection termination. For risk control, understanding the differences between cases that cause post-termination seismicity and those that do not is necessary. For this purpose, we used microseismic monitoring to examine the behavior of water during two injection tests, including their post-termination periods, in Okuaizu geothermal field, Japan. In this field, a new remote microseismic cluster, apart from the injection well, was created in the post-termination period of the first injection test. However, this cluster was not well activated in the second injection test. As a result, we revealed that this microseismic cluster was created on a structure that was different from the target fracture of the injection, possibly owing to pore-pressure migration in the post-termination period of the first injection. Its inactivation in the second post-termination period may be attributable to the lower magnitude of pore-pressure migration derived from the smaller amount of injected volume compared with that of the first injection test. The lower pore-pressure migration was insufficient to reactivate the seismicity. We concluded that the occurrence of seismicity after injection termination may depend on the magnitude of pressure in the injection well at the shut-in time. The Kaiser effect (i.e., a fault is not reactivated by stress that is less than the maximum stress loaded previously) could explain the observed phenomena.

Numerical Study on the Effects of Imbibition on Gas Production and Shut-In Time Optimization in Woodford Shale Formation

In shale gas formations, imbibition is significant since the tight pore structure causes a strong capillary suction pressure. After hydraulic fracturing, imbibition during the period of shut-in affects the water recovery of flowback. Although there have been many studies investigating imbibition in shale formations, few papers have studied the relationship between gas production and shut-in time under the influence of imbibition. This paper developed a numerical model to investigate the effect of imbibition on gas production to optimize the shut-in time after hydraulic fracturing. This numerical model is a 2-D two-phase (gas and water) imbibition model for simulating an imbibed fluid flow and its effect on permeability, flowback, and water recovery. The experimental and field data from the Woodford shale formation were matched by the model to properly configure and calibrate the model parameters. The experimental data consisted of the relationship between the imbibed fluid volume and permeability change, the relative permeability, and the capillary pressure for the Woodford shale samples. The Woodford field data included the gas production and flowback volume. The modeling results indicate that imbibition can be a beneficial factor for gas production, since it can increase rock permeability. However, the gas production would be reduced when excessive fluid is imbibed by the shale matrix. Therefore, the shut-in time after hydraulic fracturing, when the imbibition happens in shale, could be optimized to maximize the gas production.

Study on the Shut-in Time Law after Volume Fracturing of Glutenite Reservoir——Taking the Horizontal Well of Mahu 1 Well Area as an Example

Two horizontal wells have been put into operation in the Mahu 1 well area, the difference in geology and engineering between Mahu 1 well area and Ma 18 and Ma 131 well area is small, but the pressure and output drop rapidly after putting into production. Aiming at this problem, the micro-mechanism analysis is carried out, through the analogy with the neighboring area, and the reasonable shut in time is calculated through the derivation of theoretical infiltration rate formula. The results show that the reasonable closing time after horizontal well fracturing in the Mahu 1 well area is 18 days. Through the analysis of the mine test, the infiltration method and pressure drop method can accurately predict the reasonable shut-in time after fracturing, the research results have played a good guiding role in the production of horizontal well volume fracturing.

Pressure Buildup in a Well Produced at Constant Pressure

Summary Dimensionless analytic expressions of the well-pressure buildup resulting from shutting in a well after producing it at constant pressure were obtained, in both Laplace space and time, using different mathematical approaches to solve the pertinent differential equations, including the effects of both wellbore storage and skin damage. Such a pressure response is said to have been obtained at constant-pressure-buildup (CPBU) conditions. The well, represented by a cylindrical source of nonzero radius, produces a single compressible fluid from an infinite and homogeneous reservoir. For a vertical well, the reservoir flow is always radial and horizontal. For the first approach in Laplace space, the pressure distribution in the reservoir at the shut-in time was used as the initial condition to obtain the transient pressure response upon shutting in the well. In the second approach, the solution in Laplace space was inverted analytically, yielding an expression containing infinite integrals. Duhamel's principle was used in the third approach, yielding the same integrals as the second approach. Subject to the inherent numerical errors in the integration and inversion algorithms, all solutions gave the same numerical results over a wide range of the production period, the elapsed time since the well was shut in, the storage coefficients, and the skin damage. As required by material balance, all pressures are restored to the value of the initial reservoir pressure as the infinite reservoir eventually completely recharges the amount of fluid produced before the well being shut in. The pressure response divided by the production rate at the time the well is shut in is denoted as the specific pressure response and has the same units as the pressure response under constant rate buildup (CRBU) conditions. It is thus not surprising that the general trends of the specific pressure response and the specific pressure increment are somewhat similar for both producing conditions, and that a number of interpretation procedures developed for CRBU conditions using the exponential integrals are applicable under CPBU conditions, including use of Horner plots. The Laplace-space procedure used to obtain numerically inverted values of the pressure response under CPBU conditions can be formally extended to provide expressions for the shut-in pressure response for any rate or pressure history during the production period. Although the emphasis is on the description of the well pressure and the specific-well-pressure buildup after shut-in, and of their time derivatives, the paper also presents analytic Laplace-space expressions for the pressure and radial flow within the reservoir after the well is shut in.

Rheology of methane hydrate slurries formed from water-in-oil emulsion with different surfactants concentrations

As oil and gas production moves into ultra-deep water, hydrate blockage has been a major flow assurance issue. Transport in the form of flowing hydrate slurry is an effective method to prevent hydrate blockage with an addition of surfactants. To determine the impact of surfactants on rheological behavior of hydrate slurry, the high-pressure rheological experiment was conducted on methane hydrate slurry formed from emulsion with 50 vol% water cut but different surfactants concentrations. The emulsions were prepared with deionized water, n-decane and two non-ionic surfactants (Span 80 as an anti-agglomerant and Tween 80 as a co-surfactant). The experimental results indicate that a lower surfactants concentration would greatly accelerate hydrate formation, causing blockage in a shorter time. While the higher the surfactants concentration, the more stable the slurry when hydrate formation. As the surfactant concentration was over 5 wt% in the oil phase, slurry viscosity decreased significantly, and hydrate slurry showed a good flow performance. Furthermore, a simulation of shut-in and restart was conducted after slurry reaching a steady-state. It was found that during the first 10 min of shut-in process, yield stress at restart was basically unchanged, while when the shut-in time exceeded 20 min, the yield stress increased significantly with the increase of the shut-in time, and an increase of surfactants concentration would have a negative effect on this trend. As the surfactant concentration was over 5 wt%, the flow performance of hydrate slurry remained good after 1280 min shut-in and restart, with little change in rheological behavior.

Hydrate deposition prediction model for deep-water gas wells 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.

A study on the thermal-hydrodynamical-coupled CO2 flow process in the Ordos CCS-geological-formation

Non-isothermal flow in wellbores and geological formations is an important process associated with geologic storage of CO2. Technically, simulation of it is a highly challenging task as it often encounters phase transition problems for the fluids involved, which may greatly influence the profiles of pressure, temperature, and flowrate along the wellbore and consequently changes the injectivity of the relevant gas injection. In this paper we present a coupled non-isothermal wellbore/reservoir model for simulating the relevant flow behaviors, in which the non-isothermal wellbore flow model CO2Well and the reservoir simulator TOUGH2/ECO2N are combined to form a novel coupled flow model. The model developed is compared and verified by the existing wellbore-reservoir simulator T2Well with two CO2 injection examples. These examples demonstrate that the present method has considerable computational advantages in simulating wellbore flows when phase transition occurs. We then apply this model to the Ordos CCS demonstration project in China, and investigate the sophisticated, thermal-hydrodynamically-coupled flow processes observed there owning to injection of the condensed, cold CO2 that was directly captured from a nearby coal liquefaction plant. The results obtained by the simulation, along with the relevant field observations, provide in-depth insights into the CO2 flow behaviors in both the wellbore and the geological formation. For example, the simulation revealed that, in the wellbore, the heat exchange between the injected CO2 and the surrounding rock plays a critical role for the temperature distribution. It was also observed that phase transition occurred in the transferred period between the injection time and the shut-in time. In addition, both the simulation and field observation showed that most CO2 injected entered the topmost layer due to the high transmissivity of the rock. The simulation also showed that the temperature-change zone travelled slower than the CO2 plume. For example, the CO2 plume extended to 430 m away from the injection site after 31 months of CO2 injection, while the temperature-change zone extended merely about 90 m away, much smaller than that of the CO2 plume. The simulation suggests that the injectivity at this site is about 0.83 kg/(MPa·s). The simulation also suggests that the injection temperature should be relatively high (e.g., above −3 °C if the injection rate is more than 9.45 kg/s) to avoid formation of CO2 hydrate in the subsurface.

CH4/C2H6 gas hydrate interparticle interactions in the presence of anti-agglomerants and salinity

Gas hydrate interparticle cohesive forces are essential to evaluate hydrate interfacial properties and determine the hydrate particle agglomeration behavior. In this study, a technique was developed in a modified high-pressure micromechanical force (HP-MMF) apparatus that enables hydrate anti-agglomerants (AAs) to be evaluated at an interfacial level under deepwater petroleum flowline conditions of high pressure and low temperature in a liquid hydrocarbon-dominated system. The hydrate cohesive force was found to decrease from the baseline (23.5 ± 2.5 mN m−1) to a non-measurable force value (<0.05 mN m−1) with increasing concentration of a high-performance AA (0.25 vol% to 2 vol% of AA1). To mimic the shut-in scenario in subsea flowlines that may be required in an emergency response, cohesive force was measured with shut-in times varying from 10 sec to 18 hr. It was observed that long contact times can lead to higher cohesive forces and eventually resulting in a system failure, i.e. irreversible interparticle interactions, if the system is under-dosed. Utilizing these results, under-dosed scenarios were identified for AA1 in the model liquid hydrocarbon. In addition, salt ions were found to promote the performance of AA1, but salt only slightly reduced the force with AA2 at the same subcooling. The results demonstrate that this modified HP-MMF method can capture the differences between high and low performance AAs. These data/tests can be used to help improve our understanding on the gas hydrate interfacial properties and determine the minimum effective dosage of AA additives for hydrate mitigation treatments in subsea flowlines.

Hydrodynamic Equilibrium Simulation and Shut-in Time Optimization for Hydraulically Fractured Shale Gas Wells

Post-fracturing well shut-in is traditionally due to the elastic closure of hydraulic fractures and proppant compaction. However, for shale gas wells, the extension of shut-in time may improve the post-fracturing gas production due to formation energy supplements by fracturing-fluid imbibition. This paper presents a methodology using numerical simulation to simulate the hydrodynamic equilibrium phenomenon of a hydraulically fractured shale gas reservoir, including matrix imbibition and fracture network crossflow, and further optimize the post-fracturing shut-in time. A mathematical model, which can describe the fracturing-fluid hydrodynamic transport during the shut-in process, and consider the distinguishing imbibition characteristics of a hydraulically fractured shale reservoir, i.e., hydraulic pressure, capillarity and chemical osmosis, is developed. The key concept, i.e., hydrodynamic equilibrium time, for optimizing the post-fracturing shut-in schedule, is proposed. The fracturing-fluid crossflow and imbibition profiles are simulated, which indicate the water discharging and sucking equilibrium process in the coupled fracture–matrix system. Based on the simulation, the hydrodynamic equilibrium time is calculated. The influences of hydraulic pressure difference, capillarity and chemical osmosis on imbibition volume, and hydrodynamic equilibrium time are also investigated. Finally, the optimal shut-in time is determined if the gas production rate is pursued and the fracturing-fluid loss is allowable. The proposed simulation method for determining the optimal shut-in time is meaningful to the post-fracturing shut-in schedule.

Experimental investigation of partially hydrolyzed polyacrylamide–hexamine–pyrocatechol polymer gel for permeability modification

The crosslinked polymer gel systems are most widely used as injection fluids for the maintenance of adequate mobility control and favorable permeability profiles within the reservoir. The application of these systems requires careful monitoring of the gelation behavior to avoid premature gelation or prolongs shut-in times under reservoir conditions. The paper deals with the investigation of disproportionate permeability reduction (DPR) of reservoir rock using partially hydrolyzed polyacrylamide–hexamine–pyrocatechol gels. Mutual correlation was observed between gelation time of the developed organic polymer gel in bulk gelation studies and other parameters such as the concentration of polymer and crosslinkers as well as temperature. An increase in gelation time was observed with the increase in the concentration of polymer and crosslinkers as well as temperature. The stability of the developed polymer gel was observed at the polymer and crosslinker concentration from 0.9 to 1.1 and from 0.3 to 0.5 wt.%, respectively. The thermal stability of the developed polymer gel was exhibited at a higher temperature of about 120 °C. The stabilized polymer gel was used for in situ gelation study to evaluate the plugging ability of the polymer gel in sand pack. In situ gelation studies showed a good injectivity and plugging ability with potentiality for the DPR in the oil fields.

A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

As the mature oil fields have stepped into the high water cut stage, the remaining oil is considered as potential reserves, especially the attic oil in the inclined fault-block reservoirs. A novel assisted gas–oil countercurrent technique utilizing gas oil countercurrent (GOC) and water flooding assistance (WFA) is proposed in this study to enhance the remaining oil recovery in sealed fault-block reservoirs. WFA is applied in our model to accelerate the countercurrent process and inhibit the gas channeling during the production process. Four comparative experiments are conducted to illustrate enhanced oil recovery (EOR) mechanisms and compare the production efficiency of assisted GOC under different assistance conditions. The results show that WFA has different functions at different stages of the development process. In the gas injection process, WFA forces the injected gas to migrate upward and shortens the shut-in time by approximately 50% and the production efficiency improves accordingly. Compared with the basic GOC process, the attic oil swept area is extended 60% at the same shut-in time condition and secondary gas cap forms under the influence of WFA. At the production stage, the WFA and secondary gas cap expansion form the bi-directional flooding. The bi-directional flooding also displaces the bypassed oil and replaced attic oil located below the production well, which cannot be swept by the gas cap expansion. WFA inhibits the gas channeling effectively and increases the sweep factor by 26.14% in the production stage. The oil production increases nearly nine times compared with the basic GOC production process. The proposed technique is significant for the development of attic oil in the mature oil field at the high water cut stage.

Well controls and placement optimisation using response-fed and judgement-aided parameterisation: Olympus optimisation challenge

In this work, several techniques, with an emphasis on parameterisation, are proposed and used to address all the three exercises of Olympus optimisation challenge. For the well controls exercise, a response-fed parameterisation is introduced in which the decision variables are water-cut threshold and re-opening time for each producer and shut-in time and shut-in period for each injector. This parameterisation allows a non-uniform control across the realisations. In the parameterisation of the field development, reservoir engineering judgements are utilised to make the solution space smaller and accordingly expedite the convergence. These judgements allow constraining the wells to high oil-in-place regions, by imposing piecewise linear polynomials, and also constraining the wells to reservoir top and bottom, by approximating depths using kriging. Also, the preliminary analyses suggest that the variables corresponding to the location of platform can be separated from the placement of the wells. For the joint optimisation (sequential and simultaneous), the combination of the two sets of variables is used. A robust population-based algorithm, (μ + λ) Evolution Strategy, was utilised for all the three exercises. In addition, a stochastic adaptive selection of realisations is introduced to reduce the computation time, which works based on rank (Spearman’s) correlation coefficient between each realisation net-present-value (NPV) and the full-set NPV. In order to minimise the overall optimisation time, simulations were executed in parallel on a cluster. In the well controls exercise, the reactive strategy was outperformed by the proposed technique, from the first generation, and the algorithm converged after 16,500 (60 equivalent) simulations, to an E[NPV], 7.8%, higher than the reactive’s. In the field development exercise, an E[NPV] of 1.37 billion dollars was obtained with 45,000 simulations. The joint (simultaneous) optimisation with nearly 60,000 simulations resulted in an E[NPV] of 1.45 billion dollars, which was 40 million dollars more than the one achieved by the sequential with about the same amount of computation.

Designing pressure build-up test on heavy oil well by alternating oil viscosity

Pressure Build Up analyses on a heavy oil well would give an inconclusive result on pressure derivative curves. Some kind of thermal injection should be performed prior to implementing the operation of Pressure Build Up test, where the heat will lower the viscosity of the reservoir fluid. The study was aimed to design a proper well test for N-7 Well using a simulator. Since the Pressure Build Up test was intended to reach radial flow period within shut in time of 100 hours, the viscosity of fluid should be reduced to 24.8 cp or less. Sensitivity of several parameters namely viscosity, permeability, porosity, and shut-in time was conducted in designing Pressure Build Up test. This sensitivity would give various radius of investigation. Furthermore, the study was continued to correlate radius of investigation as a function of the parameters mentioned above.

A new simulator to determine thermal disturbance and recovery processes during wellbore drilling: Experimental validation with a scaled-down wellbore prototype

In the present study, a novel simulator is developed. The simulator is built upon the model presented by (Wong et. al. 2017) but considering a Robin boundary condition at the interphase between the rock formation and the bottom-hole. Additionally, simulation results are compared against experiments in a scaled-down bore-hole set-up, emulating the most relevant aspects of a real perforation, such as: behaving as a semi-infinite media and considering sequential circulation and shut-in times with varying durations. Moreover, all thermal parameters are independently estimated, such as to diminish cross-correlation between model parameters. Deviations between experiments and the simulations of the proposed model are below 1.2%, for all cases. Deviations for the present model are about an order of magnitude smaller than those obtained by Wong et. al. 2017).

Evaluating the potential for oil recovery by imbibition and time-delay effect in tight reservoirs during shut-in

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 T2 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 (T2 < 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.

Identification and illustration of relationships between produced gas and water in marcellus under different spatial and temporal domains through data-driven analytics - Nonparametric model

Understanding the relationship between produced gas and flowback/produced water is important for both shale gas well operation optimization and well performance enhancement; however, it is not fully understood due to complex flow mechanisms and interactions/feedback among various geoscience and engineering controls. Data-driven analysis, as an alternative way, could inversely provide valuable insights on the relationship between produced gas and water, to adjust future development plans for well/regional optimal economic production.An auto-updated nonlinear data analytics method was applied to evaluate the relationship between water and gas in different spatial and temporal domains, to inversely correlate the micro-scale flow mechanisms from macro-scale data. In this study, the cases were covered with both wet and dry shale gas regions, as well as short and long shale gas production periods. Fracture-fluid flowback is defined as water production within one month, following a fracture treatment (exclusive of well shut-in time), and the produced water is 1–3 years cumulative water production. 114 wells from the Marcellus Formation, in wet and dry gas regions of northwestern West Virginia, were selected to investigate the relationship between fracture-fluid flowback and corresponding one-month gas production. 67 Marcellus wells in Pennsylvania were selected to study the relationship between produced water and corresponding gas production across different time periods ranging from one to three years. The results indicate that the relationship between gas and fracture-fluid flowback in the wet gas region is positive while negative in the dry gas region. The discussion of water flow format was done by comparing the water gas ratio at reservoir conditions and at the surface condition. WGR (water gas ratio) is high (>9 bbl/mmcf) during the 1st-year and then leveled off at 3 bbl/mmcf after the 1st-year, indicating water initially be produced through displacement, and then be produced through evaporation.

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.