Shut-in Period Research Articles

Reducing Residual Oil Saturation: Underlying Mechanism of Imbibition in Oil Recovery Enhancement of Tight Reservoir

SummarySpontaneous imbibition (SI) is regarded as an effective method to improve the oil recovery in a tight sandstone reservoir, which leads to a significant change in fracturing design and flowback treatment. However, a longtime shut-in period would aggravate the retention of fracturing fluid, which is in contradiction with high production in the field. It is imperative to understand how SI works during shut-in time, so as to maximize the effect of imbibition in oil recovery enhancement. In this study, a series of experiments were conducted to simulate the status of residual oil saturation so that the inner mechanism of imbibition on oil recovery can be investigated. Low-field nuclear magnetic resonance (LF-NMR) was used to provide direct observation of phase changes in different pore sizes. The experimental results show a positive effect of imbibition on residual oil reduction. This phenomenon further elucidates the observations made during the well shut-in, soaking period, and low flowback efficiency. This study aims to understand the mechanism of SI behavior and help to improve the accuracy of production prediction.

Novel Near-Wellbore Fracture Diagnosis for Unconventional Wells Using High-Resolution Distributed Strain Sensing during Production

SummaryThe characteristics of hydraulic fractures in the near-wellbore region contain critical information related to the production performance of unconventional wells. We demonstrate a novel application of a fiber-optic-based distributed strain sensing (DSS) technology to measure and characterize near-wellbore fractures and perforation cluster efficiency during production. Distributed fiber-optic-based strain measurements are made based on the frequency shift of the Rayleigh scatter spectrum, which is linearly dependent on strain and temperature changes of the sensing fiber. Strain changes along the wellbore are continuously measured during the shut-in and reopening operations of a well. After removing temperature effects, extensional strain changes can be observed at locations around the perforation cluster during a shut-in period. We interpret that the observed strain changes are caused by near-wellbore fracture aperture changes caused by pressure increases within the near-wellbore fracture network. The depth locations of the measured strain changes correlate well with distributed acoustic sensing (DAS) acoustic intensity measurements that were measured during the stimulation of the well. The shape and magnitude of the strain changes differ significantly between two completion designs in the same well. Different dependencies between strain and borehole pressure can be observed at most of the perforation clusters between the shut-in and reopening periods. We assess that this new type of distributed fiber-optic measurement method can significantly improve understanding of near-wellbore hydraulic fracture characteristics and the relationships between stimulation and production from unconventional oil and gas wells.

Characterizing mineralization on low carbon steel exposed to aerated and degassed synthetic hydraulic fracture fluids

This study investigates the mineralization occurring at the interface between injected hydraulic fracturing fluids and steel production casing during the shut-in period of unconventional shale wells. Mild steel coupons were reacted with synthetic hydraulic fracturing fluids with varying base fluid and dissolved gas concentrations. Experiments were carried out in an autoclave system set at 50 °C and 2000 PSI for 2 and 14 days. Physical and mineralogical changes to the steel coupons’ surface were characterized using an FEI Quanta 600 field emission gun (FEG) scanning electron microscope (SEM) and a PANalytical XPert Pro diffractometer. Barite precipitation occurred ubiquitously during the first 48 h in all experimental scenarios. Sulfate radicals created from degradation and reduction of ammonium persulfate breakers facilitate barite formation. Concomitant barite and corrosion related precipitates on the sample surfaces suggest iron hydroxy salts act as nucleation sites for mineral scale growth. These results suggest hydraulic fracturing fluids may have deleterious effects on the wellbore before production of the well begins.

Monitoring of seismic attenuation change associated with vapor-liquid phase transition using time-lapse reflection seismic data in Kakkonda geothermal field, Japan

Seismic wave attenuation can potentially be used for the investigation of the fluid phase and flow properties in a fractured reservoir. However, seismic attenuation estimation is easily affected by various factors, such as tuning effects, source and receiver coupling, and effects from near-surface weathering layers. Time-lapse seismic attenuation estimation can avoid these problems because the above factors are canceled between surveys. We conducted time-lapse attenuation estimation using three reflection seismic surveys with different timings acquired in the Kakkonda geothermal field during a 12-day period spanning a well shut-in period. To investigate geothermal fluid changes associated with increased pore pressure, we propose an approach for estimating attenuation changes between time-lapse seismic surveys. Firstly, three seismic reflection sections were obtained from the corresponding time-lapse seismic data using the modified prestack time migration method, which can handle the uncertainties of migration velocity estimation in a highly fractured and structurally very complex medium, for which accurate velocity estimation is difficult to achieve using conventional methods. Then, time-lapse attenuation was evaluated for two of the three seismic reflection sections using the spectral ratio and the centroid frequency shift methods. Numerical modeling was conducted to verify our proposed procedure. Careful preprocessing was carried out to enhance the repeatability of time-lapse seismic data, especially on the frequency content, which is indirectly related to seismic attenuation. Finally, we demonstrated an increase of attenuation associated with an increase of pore pressure in and around the known super-shallow vapor-dominated reservoir during a short period (7 days) spanning from one day before the shut-in of producing well to a week after that. A possible cause of this short-period attenuation increase could be the vapor-liquid phase transition in the reservoir.

GHGT-15 Quest CCS facility - Halite Injectivity Damage Remediation in CO <sub>2</sub> Injection Wells

The Quest CCS facility (located in Alberta, Canada) is a fully integrated carbon capture, transport and storage facility operated by Shell Canada. It continuously captures and stores about 1.1Mt of CO2 per year, with injection expected to continue until 2040. Following a month of performance testing, commercial operations began in October 2015, and through November 2020, more than 5.6 Mt of CO2 have been sequestered. The commercial scale deployment of Carbon Capture and Storage (CCS) as a viable greenhouse gas (GHG) emissions reduction technology requires that the CO2 be continuously injected at material and predictable rates into geological formations (e.g. saline aquifers). While the initial injectivity for the Quest CO2 injection wells was very high, significant injectivity reductions have been observed following short well shut-in periods associated with well intervention work. Although these injectivity reductions currently do not form an operational constraint, if the trend of injectivity reductions continue, it may become an issue for future operations. Developing the capability to reduce or even reverse these injectivity reductions may be key to maintaining reliable CO2 injection. The Quest CCS project sequesters CO2 into the Basal Cambrian Sands (BCS) formation, which was initially filled with sodium chloride saturated brine. As dry CO2 is injected, water can evaporate from the brine into the CO2 driving precipitation of halite. This precipitation can occur in various locations including inside the wellbore, perforation tunnel, near wellbore area and further afield in the BCS formation. Plugging of the perforation tunnel and pore throats in the near wellbore area can cause injectivity damage. A downhole video log performed in April 2018 on the Quest IW 7-11 CO2 injection well showed solids plugging in numerous perforations. The most probable substance to precipitate in the downhole environment of a Quest CO2 injector well is halite. While the solids were not sampled for compositional analysis during the April 2018 downhole video log, downhole samples were obtained during the pre-work leading up to the halite remediation treatment. A viable mechanism for inducing halite damage during well intervention shut-in events is that deposited halite is dislodged and subsequently plugs the critical perforation tunnel and near wellbore areas. One method to remediate halite damage is to inject a water-based fluid to dissolve the halite precipitate, thereby removing it from the perforation tunnel and near wellbore area, where it can damage the well injectivity performance. Quest performed the first halite remediation treatment on one of the CO2 injector wells in 2020. The objective of this paper is to present the design, execution and results of this initial halite remediation treatment. An outline of the design of the halite remediation treatment will be provided. Aspects of the treatment design including treatment volume, rate, pressure, treatment fluid composition, fluid diversion, tubing stress analysis and hydrate mitigation will be discussed. Subsequently the halite remediation treatment as executed in the field will be reviewed including the timing of operations and the pumping pressure and rate data. Finally, to evaluate the effectiveness of the treatment, skin analysis and injectivity trends pre and post remediation treatment shall be presented. Halite remediation treatments have the potential to become key methods for maintaining injectivity performance of CO2 injection wells in saline aquifers.

Comparative study of different enhanced oil recovery scenarios by silica nanoparticles: An approach to time-dependent wettability alteration in carbonates

Recently, nanoparticles (NPs) have been proven to be effective chemical agents for enhanced oil recovery (EOR) purposes. Many studies implemented various Nano-EOR scenarios, including slug nanofluid injection, continuous nanofluid-flooding, and pre-soaking by nanofluids. However, since the EOR performance of NPs is limited by factors such as the cost of nanofluids preparation and the potential rock permeability impairment, a lack of an efficient Nano-EOR scenario is felt. This study intends to evaluate the efficiency of the mentioned Nano-EOR scenarios to propose a more desirable Nano-EOR plan. The results showed that silica NPs could decrease interfacial tension of water/oil system from 25.1 mN/m to 9.3 mN/m. Also, wettability alteration induced by silica NPs is a time-dependent process, in which it took around 7 days for NPs to exhibit their optimal potential for wettability alteration of the carbonate rock. Equilibrium contact angle values of 66 and 23 degrees were obtained using 0.1 and 0.3 wt% of silica nanofluids. Accordingly, a 7-day shut-in period was carried out after nanofluid flooding (meaning pre-soaking by nanofluids), before flushing by low salinity water. Core flooding tests showed ultimate oil recovery values of 78 and 71% of original oil in place (OOIP) through the pre-soaking scenario by 0.1 and 0.3 wt% of silica nanofluids, which were higher than slug nanofluid injection and continuous nanofluid flooding scenarios with 49 and 38% of OOIP, respectively. Permeability reduction was intensified with nanofluids concentration and a 24% permeability impairment was achieved by injecting 0.3 wt% of silica nanofluid. Primary reasons associated with differences in oil recovery values were dynamic performance of silica NPs on wettability alteration, oil snap-off, and pore plugging due to the adsorption and straining of NPs. Findings of this study revealed the importance of an optimal Nano-EOR scenario selection in oil-wet carbonates.

Method Quantifies Separator-Oil Shrinkage

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19775, “Quantifying Separator-Oil Shrinkage,” by Mathias Lia Carlsen, SPE, and Curtis Hays Whitson, SPE, Whitson, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. In tight unconventionals, oil and gas rates often are measured daily at separator conditions. Consequently, converting these rates reliably to volumes at standard conditions is necessary in cases where direct stock-tank measurements are not available. Because of changes in producing-wellstream compositions and separator conditions, the separator-oil shrinkage factor (SF) can change significantly over time. The complete paper presents a rigorous and consistent method to convert daily separator rates into stock-tank volumes. Recommendations for developing field-specific shrinkage correlations using field test data also are proposed. SF and Flash Factor (FF) Separator-Oil SF. Separator-oil SF is the fraction of metered separator oil rate that remains (or transforms into) stock-tank oil after further processing to standard conditions of 1 atm and 60°F. Put simply, the SF quantifies the decrease in oil volume from separator conditions to stock tank. The magnitude can range from less than 0.65 to 0.99. Separator-Oil FF. Separator-oil FF is the ratio of liberated gas from metered separator oil after further processing to standard conditions of 1 atm and 60°F. The FF accounts for the increase in gas volume from separator conditions to stock tank and explains why oil is shrinking (i.e., gas is coming out of the solution). The magnitude of the FF can range from 5 to 1,000 scf/STB. Total producing gas/oil ratio (GOR) can be calculated easily when SF and FF are known. An SF always is associated with an FF and is literally the solution GOR of the separator oil. Both SF and FF are a function of the top-side surface process and an associated wellstream composition. Surface Process. The surface process represents the number of topside separation stages and the associated separator pressure and temperature of each stage. In shale basins, two- and three-stage separation trains are common. The number of separation stages typically is fixed throughout the lifetime of a well. However, the separator temperature and pressure may vary significantly. Wellstream Composition. The well-stream composition quantifies the relative amounts of different components flowing out of a well at a given day. This measurement is typically expressed in mol%. Tight unconventional basins contain many kinds of in-situ reservoir fluid compositions from dry gas to black oils. The produced-wellstream compositions from these systems tend to change considerably with time because of producing flowing bottomhole pressures below the saturation pressure, as seen in the field example presented in Fig. 1. In the figure, the shut-in period after approximately 330 days results in a transient period with large compositional changes.

Application of Gated Recurrent Unit (GRU) Neural Network for Smart Batch Production Prediction

Production prediction plays an important role in decision making, development planning, and economic evaluation during the exploration and development period. However, applying traditional methods for production forecasting of newly developed wells in the conglomerate reservoir is restricted by limited historical data, complex fracture propagation, and frequent operational changes. This study proposed a Gated Recurrent Unit (GRU) neural network-based model to achieve batch production forecasting in M conglomerate reservoir of China, which tackles the limitations of traditional decline curve analysis and conventional time-series prediction methods. The model is trained by four features of production rate, tubing pressure (TP), choke size (CS), and shut-in period (SI) from 70 multistage hydraulic fractured horizontal wells. Firstly, a comprehensive data preprocessing is implemented, including excluding unfit wells, data screening, feature selection, partitioning data set, z-score normalization, and format conversion. Then, the four-feature model is compared with the model considering production only, and it is found that with frequent oilfield operations changes, the four-feature model could accurately capture the complex variance pattern of production rate. Further, Random Forest (RF) is employed to optimize the prediction results of GRU. For a fair evaluation, the performance of the proposed model is compared with that of simple Recurrent Neural Network (RNN) and Long Short-Term Memory (LSTM) neural network. The results show that the proposed approach outperforms the others in prediction accuracy and generalization ability. It is worth mentioning that under the guidance of continuous learning, the GRU model can be updated as soon as more wells become available.

Influence of Reactive Flow Conditions on Barite Scaling in Marcellus Shale during Stimulation and Shut-In Periods of Hydraulic Fracturing

Barite scaling during the low-flow, shut-in period in hydraulic fracturing operations during shale gas production has been intensively studied, but scaling during the stimulation periods when large...

Experimental Investigation of the Pressure Decay Characteristics of Oil Reservoirs after Fracturing Operations.

Field experience shows that extending shut-in periods are conducive to increasing tight oil production after fracturing operations. Understanding the regularity of pressure decay is helpful to establish an appropriate shut-in time. However, the characteristics and influencing factors of pressure decay are unclear. This paper studies the porosity, permeability, mineral composition, and pore structure of samples in six different blocks. The pressure decay regularity is tested according to an independently designed indoor shut-in experimental device, and the oil distribution of experimental samples is monitored using nuclear magnetic resonance technology. The results show that the fracturing fluid enters the matrix pores under the action of percolation to slowly drive out the oil, causing the well pressure to decay over time. There are three types of pressure decay characteristics: concave type, fluctuation type, and quadratic type. Compared with conventional sandstone, the pressure decay rate of tight reservoirs is slower, and the pressure decay characteristics are more complicated. Clay mineral-rich reservoirs will swell when exposed to water. As a result, the strength of the framework will be weakened and collapsed. What’s more, it will cause blockage of the throat, blocking the flow of oil and the decay of pressure. In addition, the rate of pressure decay is also related to the volume of fracturing fluid, initial borehole pressure, and formation closure stress. At a certain proppant thickness (fracture width), the larger the fracturing fluid volume, the larger the fracture surface area and the faster the pressure decay rate; Moreover, the greater the initial shut-in pressure, the greater the pressure difference and the faster the decay rate; the formation closure stress causes the core porosity and the permeability to decrease, resulting in a decrease in the decay rate. The experimental results are of great significance for establishing a proper shut-in time and enhancing the oil recovery of tight reservoirs.

Experimental and Analytical Investigation of Sand Production in Weak formations for Multiple Well Shut-Ins

Sand production is a severe problem in oilfields and is majorly associated with weak and unconsolidated formations. Therefore, identifying the expected amount and rate of sand has been approached by different analytical and numerical prediction methods. Within them the former requires less computational time and therefore being widely used. However, despite some of the analytical models proved to be fairly predictive for sand production during steady-state flow, they cannot be used directly for the wells with complex production profiles. The current study focuses on the experimental investigation of the sand production pattern during well production and shut-in periods. The laboratory work was conducted on artificial sandstone replicating weak Cretaceous formations in Kazakhstan using customized High Pressure Consolidation System (HPCS) for sand production experiments. HPCS accommodates a sandstone sample of a large diameter to diminish boundary effect when the fluid is injected. The tests were conducted at different overburden stresses as well as pressure drawdowns in several well shut-in runs. The paper presents a modification of the classical steady-state flow analytical solution incorporating field and fluid conditions as well as the dependence on the well shut-in runs. The model showed good convergence with the experimental and well data.

A new physical modeling for two-phase wellbore storage due to phase redistribution

Pressure transient analysis is one of the main dynamic sources for reservoir characterization. The main task in well test interpretation is to understand the reservoir properties using the bottom-hole pressure behavior. Unfortunately, one of the main factors that can affect this task is wellbore storage effects, especially in cases that we have a non-ideal one. In pressure build-up test if pressure is below the bubble point or if gas enters into the wellbore, the phase redistribution can happen during the shut-in period. This phenomenon causes pressure anomalies. Besides, due to pressure increase or existence of under-saturated liquid in the wellbore, the gas starts to dissolve, and it is led to pressure decrease. So the pressure build-up test is dominated by three main factors: firstly, the pressure increase resulted from build-up test. Secondly, the pressure increase due to phase redistribution. Finally, the pressure decrease due to gas dissolution. These effects are known as non-ideal wellbore storage. Most of the studies focused on non-ideal wellbore storage try to propose an empirical equation to simulate the pressure curve more accurately instead of proposing an analytical model, because of the large number of effective parameters in an actual case.This paper is proposing a new analytical model for changing wellbore storage and analysis of gas phase segregation during the pressure build-up test in the existence of the under-saturated liquid. This model is further modified for two-phase flow when pressure falls below the bubble point in the wellhead. When the well is shut in at the start of build-up test, gas bubbles travel upward because of the buoyancy force. This model is presented for the case of dissolving gas pockets while rising in the wellbore. The novelty of this paper in comparison to previous researches is in developing a new physical model for two-phase wellbore storage done by modeling pressure increase due to gas bubbles rise while modeling gas dissolution against time.In this study, first, the basic assumptions for simplifying the model are described and the basic theory behind the proposed model is explained. Then a simple model without gas dissolution, using Laplace transformation, is introduced. Next, the modified model considering gas dissolution effect is proposed. A synthetic case is considered and the corresponding well test type curves are generated using the proposed method. Finally, the comparison between the proposed model and a real build-up case is made. The result is consistent with the typical non-ideal wellbore storage that is seen in the literature.

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.

A laboratory study of microcracks variations in shale induced by temperature change

When fracturing in shale gas reservoirs, the temperature distribution will change sharply due to the injection of a large amount of fracturing fluid. And then the temperature returns to the original formation temperature during shut-in period after fracturing. To investigate the influence of temperature variation, hydration, and temperature change rate, variations of microcracks were characterized by 3 sets of experiments. To simulate the fracturing and soaking process, another one set of experiments were conducted under the coupling effect of hydration and temperature. With digital image processing techniques, the change of cracks can be visualized and quantitatively analyzed. The reconstructed 3D cracks images show that temperature variation significantly affects the microstructure of shale. An interesting result was found that crack extension was not induced by hydration, but drying. So there is a possible additional effect of temperature on hydration experiments, which was neglected in previous hydration or spontaneous imbibition experimental studies. The comparison of gradual heating and rapid cooling shows that crack extension is also dominated by temperature change rate. The distribution variation of cracks and quantitative analysis show that the total area of crack walls could further increase after heating in the deionized water. A combination of hydration and heating is more likely to lead to the extension of cracks than individual effect. Based on experimental results, two suggestions were proposed to guide the fracturing and soaking process: (1) Increase the temperature difference between fracturing fluid and formation shale. (2) Shut-in and soaking for a period after fracturing.

Rigorous Estimation of the Initial Conditions of Flowback Using a Coupled Hydraulic-Fracture/Dynamic-Drainage-Area Leakoff Model Constrained by Laboratory Geomechanical Data

Summary The application of rate-transient-analysis (RTA) concepts to flowback data gathered from multifractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulic-fracture volume/conductivity. However, the initial fluid pressures and saturation in the fracture network and adjacent reservoir matrix are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. In this study, we present a semianalytical flow model, coupled with a hydraulic-fracture (fracture) model and constrained with laboratory-based geomechanical data, for evaluating the initial conditions of flowback. In previous work, a semianalytical model based on the dynamic-drainage-area (DDA) concept was used to simulate water-based fluid leakoff from an MFHW into a tight oil reservoir (Montney Formation, western Canada), with minimal mobile water, during and after fracturing operations. The model assumed that each fracturing stage can be represented by a primary hydraulic fracture (PHF) containing the majority of the proppant, and an adjacent nonstimulated reservoir (NSR) or enhanced fracture region (EFR), which is an area of elevated permeability in the reservoir caused by the stimulation treatment. Each region was represented by a single-porosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through using a simple analytical fracture model. Although this approach was considered novel, several improvements and additional laboratory constraints were considered necessary to yield more accurate predictions of initial flowback conditions. In the current work, the modeling approach described previously was improved by representing the EFR with a dual-porosity system; fully coupling the fracture model (used for PHF creation and propagation) with the DDA model for fluid-leakoff simulation into the EFR and adding a proppant-transport model; and modeling the shut-in period. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously gathered laboratory data was used. Laboratory-derived propped (PHF) and unpropped (EFR) fracture-permeability/conductivity data as a function of pore pressure, as well as fracture-compressibility data, were used as constraints for the model. It should be noted that our model assumes that fracture closure has no effect on the pressure/saturation of the PHF/EFR/matrix. The improved model was reapplied to the tight oil field case and yielded more realistic estimates of initial flowback conditions, enabling more confident history matching of flowback data. The results of this study will be important to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring proper model creation.

Numerical investigation of water retention in secondary fractures and apparent permeability modeling in shale gas production

During the hydraulic fracturing process, the fracturing fluid may cause water retention, if the nearby secondary fractures subsequently close and get disconnected due to changes in effective stress distribution during flowback and production. The circumstances and detailed mechanisms associated with this phenomenon are still poorly understood. In this work, a coupling scheme for incorporating a pressure-dependent apparent permeability model in reservoir simulation is implemented. The numerical models are subsequently used to investigate the impacts of water retention and apparent permeability modeling on gas production and water flowback.A high-resolution 3D reservoir model is constructed based on the field data obtained from the Horn River shale gas reservoir. Stochastic 3D discrete fracture netsork (DFN) model is upscaled into equivalent continuum dual-porosity dual-permeability (DPDK) model by analytical techniques. An apparent permeability (Kapp) model is employed to model transport mechanisms in nano-sized pore systems. In order to capture the pressure dependency, a novel coupling scheme is developed to facilitate the updating of Kapp and effective stress after a certain designated time interval. In addition, a novel method involving rock-type indicators is introduced to represent the open and closed states of secondary fractures, facilitating the modeling of stress-dependent closure of the secondary fracture system. Two secondary fracture closure behaviors (i.e., abrupt closure and gradual closure) are considered in our study.The results indicate that fracture closure would affect the gas production and water recovery, particularly if the near-well fractures are disconnected; the effect would be further exaggerated for a denser fracture network; fracture closure would also affect the matrix water retention near the well. Neglecting the effects of Kapp could essentially overestimate the contribution of hydraulic fracture for a certain observed gas production. The existence of secondary fractures could also enhance water loss during flowback. It is concluded that gas and water production would increase if less water is imbibed into the matrix during the shut-in period in the presence of disconnected secondary fractures. It is also observed that a shorter shut-in period may be beneficial to both water and gas recovery.This work presents a novel, yet practical, scheme for coupling stress-dependent matrix apparent permeability and fluid flow, as well as modeling pressure-dependent fracture closure. This modeling scheme can be readily integrated in most commercial reservoir simulation packages. The results have revealed several potential scenarios of water loss, along with the associated implications on optimal operational strategies and estimation of stimulated reservoir volume.

Assessing the hyperbolic trend in well response involving pressure, fluid and heat-flow rates

This paper explores the application of the Arps’ hyperbolic relation beyond the rate-decline analysis for reserves assessment in conventional reservoirs. Although intended for the late-time boundary-dominated flow, the hyperbolic approach appears to work well for both the transient temperature and -pressure responses to attain the equilibrium condition. Given the simplicity and ease of use, this approach should gain traction among practitioners.The temperature responses remain in a transient state in a typical shut-in period, given the slow nature of heat diffusion compared to its fluid counterpart. Also, in a complex reservoir geometry, pressure transients may take a substantial period to reach all the boundaries to convey the desired average-reservoir pressure. More importantly, the admixture of no-flow and constant-pressure boundaries in a reservoir flood environment virtually negates the application of the conventional analytical tools, unless rate-transient analysis or related methods can be applied in the reservoir-depletion stage.This paper attempts to provide credence to the proposed solution approach by way of using the simulated pressure-transient responses in various reservoir geometries, and temperature buildup and falloff responses obtained from field data. In both cases, we show that the Arps’ method, initially intended for analyzing rate decline in a boundary-dominated system, can be used for analyzing transient pressure and temperature responses for estimating their respective current conditions. Overall, we used several synthetic cases involving both oil and gas reservoirs. Field examples included gas leakage for annular pressure buildup, gas decline rate in a coalbed-methane reservoir, and studying temperature transients in a gas well.

Adsorption Morphology of Nano Scale Inhibitors for Oilfield Mineral Scale Mitigation

Formation of mineral scales is a major issue in oil and gas industry which requires the use of scale inhibitors via squeeze treatment to mitigate the problem. Unfortunately, the retention ability of the existing scale inhibitor is low due to low adsorption of scale inhibitors onto the mineral surface, resulting in less efficient performance of scale inhibition. Recent advancement shows that nano scale inhibitors are believed to be able to migrate deep into reservoirs and adsorb onto the mineral surface during the shut-in period. Since the adsorption ability of scale inhibitors onto the mineral surface is an important characteristic, in this work adsorption morphology of several nano scale inhibitors onto mineral surface was investigated. For this purpose, this paper first describes the synthesis of these nano scale inhibitors which are nano Ca-DTPMP, nano Si-Zn-DTPMP, and nano Si-Ca-DTPMP. Results from Transmission Electron Microscopy analysis indicate the particle size of these nano scale inhbibitors in comparison to the commercial DTPMP and Ca-DTPMP. To investigate the adsorption morphology of these nano scale inhibitors onto mineral surface, static adsorption tests were done using Kaolinite as the selected mineral. Results from Field Emission Electron Microscopy analysis show the morphological changes of the Kaolinite surface after application of the scale inhibitors. Nano Si-Zn-DTPMP scale inhibitor exhibits smallest particle size of 31 nm to 37 nm based on the TEM image. As supported by the FESEM image on the adsorption morphology, this small particle size contributes to better adsorption of this scale inhibitor than its counterparts.

A New Intermittent Pumping Design for Fluid Shortage Wells

Low oil price requires oil companies to reduce costs and increase benefits. The wells with deficient fluid supplies approximately account for 20–30% of all producing wells, and this situation is even worse in the old oilfields. Intermittent production is an effective way to reduce the cost and increase the system efficiency to overcome the shortage of oil supply from the reservoir. The key is to optimize the intermittent pumping scheme, i.e., to design reasonable shut-in and operating periods. In this study, this is achieved using the dynamic change of the fluid level in the wellbore. From the electrical power curve to the dynamometer card, the dynamic drop of the fluid level can be obtained, and thus the optimal operation time of the well; at last, from the inflow performance of the well, the optimal shut-in period can be obtained. This method shows a good application in the field through a case study.

Changes in retained fracturing fluid properties and their effect on shale mechanical properties

To understand the fluid-shale interactions and the mechanisms that produce cracks during the retention of the fracturing fluid. This paper details experiments performed in shale particle immersion and core plug imbibition, and it investigates changes in fluid properties during a shale well shut-in period at the Longmaxi formation in Southeast Chongqing, China. The results indicate that soluble salts in a shale formation are dissolved during fracturing fluid retention in a shale reservoir, causing the salinity and pH of the fracturing fluid to increase significantly and eventually resulting in the formation of a weakly alkaline solution. Furthermore, fracturing fluid retention significantly reduces the mechanical strength of shale. In the experiments, the elasticity modulus and Poisson's ratio of the shale decreased by 85% and 54%, respectively, which was immersed in the fracturing fluid for seven days. Two types of forces, repulsive hydration and electric double-layer repulsion, are shown to be the main factors that lead to the formation of a large number of microcracks. The repulsive hydration pressure force is in a short range, operating over only a few nanometers, while the electric double-layer repulsion force operates over a long distance and can act between clay mineral slices. As the concentration of the solution increases, the double-layer repulsive force increases, though the range over which it acts becomes shorter. The increase in the OH− concentration of the solution also accelerates crack propagation. These conclusions are conducive to developing reasonable rules for fracturing fluid flowback in shale gas wells.