Flowback Period Research Articles

A Semianalytical Approach To Model Two-Phase Flowback of Shale-Gas Wells With Complex-Fracture-Network Geometries

Summary Two-phase flow is generally significant in the hydraulic-fracturing design of a shale-gas reservoir, especially during the flowback period. Investigating the gas- and water-production data is important to evaluate stimulation effectiveness. We develop a semianalytical model for multifractured horizontal wells by incorporating the two-phase flow in both shale matrix and fracture domains. The complex-fracture network, including both primary/hydraulic fractures and secondary/natural fractures, is modeled explicitly as discretized segments. The node-analysis approach is used to discretize the networks into a number of fracture segments and connected nodes, depending on the complexity of the fracture system. The two-phase flow is incorporated by iteratively correcting the relative permeability to gas/water for each fracture segment and capillary pressure at each node with the fracture depletion. The accuracy of the proposed model is confirmed by the numerical model. Subsequently, the early-time gas- and water-production performance is analyzed by use of various fracture geometries and network configurations. The model was also used to history match an actual multistage hydraulically fractured horizontal well in the Marcellus Shale during the flowback period. The research findings have shed light on the factors that substantially influence the gas- and water-production behavior during the flowback period. We also investigate the effects of fracture-network geometries and complexities on the gas/water-ratio (GWR) diagnostic plots. The results depict that the GWR behavior on the diagnostic plots is highly dependent on fracture-network geometry, configuration, and connectivity, which could assist in deriving the critical fracture properties affecting the production performance. This work extends the semianalytical approach previously proposed for modeling single-phase to two-phase flowback problems in unconventional reservoirs with various fracture-network geometries. The method is easier to set up and is less data-intensive than use of a numerical reservoir simulator, and is capable of providing a straightforward and flexible way to model complex-nonplanar-fracture networks in a multiphase-flow environment.

Experimental Investigation on Imbibition-Front Progression in Shale Based on Nuclear Magnetic Resonance

Spontaneous imbibition is the main mechanism responsible for the retention of large amounts of fracturing fluid during the flowback period in shale gas development. Studying the mechanism of imbibition will help optimize flowback design and improve the accuracy of production prediction. Previous experiments have mainly focused on studying the relationship between the amount of liquid imbibed into shale samples and the time. However, these experiments could not describe visually the liquid saturation distribution along rock samples. In this paper, a chemical potential-dominated flow mechanism model is presented, and nuclear magnetic resonance is adopted to obtain the water saturation distribution curve in the shale rock sample during spontaneous imbibition. The tight sandstone sample is also investigated for comparison. The effects of clay mineral content, fluid salt concentration, and surfactant solution on the water saturation distribution curve are systematically investigated. Results show that the adva...

Semi-analytical model for matching flowback and early-time production of multi-fractured horizontal tight oil wells

Analysis of multi-fractured horizontal well (MFHW) production data completed in low-permeability (tight) oil reservoirs has traditionally focused on long-term (online) production after the initial flowback period. Recent studies, however, have demonstrated that important information about hydraulic fractures can be ascertained from flowback data and simulation studies are now being designed to model flowback along with the online production.In this work, a new semi-analytical model is developed specifically for modeling water and hydrocarbon production during flowback and early-time production for tight oil wells. Two flow regions are assumed: a primary hydraulic fracture (PHF) and an enhanced fracture region (EFR) adjacent to the hydraulic fracture, where reservoir permeability has been enhanced due to stimulation. Alternatively, a non-stimulated matrix region (NSR), where reservoir permeability is not enhanced due to stimulation, may be placed adjacent to the PHF. A coupled PHF-EFR model is created by assigning the average pressure in the PHF as the inner boundary condition of the EFR, and wellbore flowing pressure as the inner boundary-condition for PHF. If the initial fracture pressure is greater than reservoir pressure, the coupled model forecasts initial production to be single-phase flow of fracturing fluid, followed by two-phase flow of fracturing fluid and formation oil from the EFR to the PHF after breakthrough to the fracture. Transient flow of fluids through the PHF and EFR is modeled with the dynamic drainage area approach. Equations of coupled flow/material balance are solved iteratively at each timestep. Stress-dependent properties of fractures and matrix are handled in the solution.The robustness of this innovative approach is tested through comparison with more rigorous numerical simulation, and its practicality demonstrated with a field example. The new technique should serve as a useful tool for petroleum engineers responsible for forecasting tight oil wells exhibiting these complexities.

Numerical Investigation of Coupling Multiphase Flow and Geomechanical Effects on Water Loss During Hydraulic-Fracturing Flowback Operation

SummaryLess than half the fracturing fluid is typically recovered during the flowback operation. This study models the effects of capillarity and geomechanics on water loss in the fracture/matrix system, and investigates the circumstances under which this phenomenon might be beneficial or detrimental to subsequent tight-oil production. During the shut-in (soaking) and flowback periods, the fracture conductivity decreases as effective stress increases because of imbibition. Previous works have addressed fracture closure during the production phase; however, the coupling of imbibition caused by multiphase flow and stress-dependent fracture properties during shut-in is less understood.A series of mechanistic simulation models is constructed to simulate multiphase flow and fluid distribution during shut-in and flowback. Three systems—matrix, hydraulic fracture, and microfractures—are explicitly represented in the computational domain. Sensitivities to wettability and multiphase-flow functions (relative permeability and capillary pressure relationships) are investigated. As wettability to water increases, matrix imbibition increases. Imbibition helps to displace the hydrocarbons into nearby microfractures and hydraulic fractures, enhancing initial oil rate, but it also hinders water recovery. The results indicate that fracture closure may enhance imbibition and water loss, which, in turn, leads to further reduction in fracture pressure and conductivity. Results also suggest that more-aggressive flowback is beneficial to water cleanup and long-term oil production in stiff rocks, whereas this benefit is less prominent in medium-to-soft formations because of excessive fracture closure. Because no direct correlation between high initial oil-flow rate and improved cumulative oil production is observed, measures for increasing oil relative permeability are recommended for improving long-term oil production.This work presents a quantitative study of the controlling factors of water loss caused by fluid/rock properties and geomechanics. The results highlight the crucial interplay between imbibition and geomechanics in short- and long-term production performances. The results in this study would have considerable impact on understanding and improving current industry practice in fracturing design and assessment of stimulated reservoir volume.

CO2-Energized-Acid Treatment Reduces Freshwater Use, Boosts Well Performance

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 172620, “Successful Implementation of CO2-Energized-Acid Fracturing Treatment in Deep, Tight, and Sour Carbonate Gas Reservoir in Saudi Arabia That Reduced Freshwater Consumption and Enhanced Well Performance,” by Ataur R. Malik, SPE, Alaa A. Dashash, Saad M. Driweesh, SPE, and Yousef M. Noaman, SPE, Saudi Aramco, and Eduardo Soriano, SPE, and Alfredo Lopez, Halliburton, prepared for the 2015 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 8–11 March. The paper has not been peer reviewed. Carbon dioxide (CO2) with 30% foam quality (FQ) has been introduced for the first time during acid fracturing treatments in a tight, sour, high-pressure/high-temperature carbonate gas reservoir in Saudi Arabia to reduce consumption of fresh water, minimize reservoir damage, reduce the flowback period, and eliminate the need for nitrogen lifting with coiled tubing. The addition of liquid CO2 to hydrochloric acid (HCl) in quantities sufficient to produce emulsion allows live acid to retard and penetrate much deeper than HCl alone. Introduction Gases were introduced to the oil and gas industry primarily as an aid to recover pumped stimulation fluids. This application still accounts for the majority of use of nitrogen and CO2. Special applications, such as foaming stimulation fluids, have reduced consumption of the liquid phase significantly. Stimulation activities have been increasing dramatically in Saudi Arabia. During each stage of fracturing stimulation in Saudi Arabia, up to 3,000 bbl of groundwater is used. Up to 70% of that groundwater consumption can be reduced through the CO2-foam fracturing treatment. The application of CO2 also reduces the flowback period and eliminates the need to perform coiled-tubing nitrogen lifting, which is a unique requirement for tight and depleted reservoirs. The addition of liquid CO2 to HCl in quantities sufficient to produce viscous foam (emulsion) is one of the more significant improvements in recent years. The addition of CO2 to acid accomplishes the following: It increases the viscosity of the commingled fluid. It controls leakoff of acid. Most CO2 foamed-acid treatments are performed at matrix rates. It can easily be pumped at fracturing rates. The fracture length is determined by acid reaction rate, injection rate, fracture width, and rate of fluid loss from the fracture to the formation. It dramatically increases the efficiency of HCl. Laboratory testing with cores from the canyon reef formation indicates an improvement in penetration of live acid of almost ninefold over a conventional acid system. It cleanses the formation. Many formations are only partially soluble in HCl. The energy and viscosity of the foamed acid aid in removal of these undissolved fines from the formation. The CO2 also strips hydrocarbon from the rock, exposing it to dissolution by the acid. It improves formation permeability by the removal of stimulation and connate fluids. It dissolves more rock. An 80%-quality foam (only 20% of the volume is acid) has been proved to remove as much rock as when the entire solution is acid. It reduces or eliminates the need for swabbing. The load to recover is significantly lower than a conventional-treatment volume. The balance of the treatment (the CO2) will vaporize and aid in the recovery of undissolved fines, spent acid, and flush volumes. Because CO2 at the surface is above the critical pressure (1,071 psi) but below the critical temperature (87.8°F), CO2 is pumped into the wellbore as a liquid. It remains a liquid until heated by the formation downhole. Conversion of CO2 to a gas downhole causes no disruption of the two-phase fluid because supercritical CO2 has a high density and no abrupt expansion of CO2 occurs.

Multi-Physics Pore-Network Modeling of Two-Phase Shale Matrix Flows

We construct a three-dimensional pore-network model with mixed wettability to study the two-phase flow mechanisms in dry gas producing shales. Previous pore-scale modeling studies on shale have been focused on single-phase gas flow through the nano-pores. However, at most field sites, the majority of the injected fracking fluid does not return to the surface during the flow-back period. It is believed that a large portion of the fracking fluid imbibes into the shale matrix during the fracking process, and thus two-phase flow occurs. In addition, while the inorganic shale matrix is generally water-wet, the organic material embedded within the matrix is hydrophobic. As such, the system displays spatial heterogeneity of wettability. Other important physics are also coupled in the model. Pressure-dependent gas sorption effects are included in the organic pores, with pore size reduction accounted for in those pores. Compressibility and slip flow effects of the gas phase are included throughout the pore-network, with the latter underscoring the fact that the sizes of the nano-pores are comparable to the mean free path of the methane molecule. The coupled effects of these various physical processes are studied to determine the importance of each effect. Continuum-scale properties are computed, including relative permeability curves, as a function of fraction and structure of organic regions and type and magnitude of boundary conditions.

Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids

Spontaneous imbibition of water-based fracturing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix imbibition capacity and rate helps to determine the fracturing fluid volume, optimize the flowback design, and to analyze the influences on the production of shale gas. Imbibition experiments were conducted on shale samples from the Sichuan Basin, and some tight sandstone samples from the Ordos Basin. Tight volcanic samples from the Songliao Basin were also investigated for comparison. The effects of porosity, clay minerals, surfactants, and KCl solutions on the matrix imbibition capacity and rate were systematically investigated. The results show that the imbibition characteristic of tight rocks can be characterized by the imbibition curve shape, the imbibition capacity, the imbibition rate, and the diffusion rate. The driving forces of water imbibition are the capillary pressure and the clay absorption force. For the tight rocks with low clay contents, the imbibition capacity and rate are positively correlated with the porosity. For tight rocks with high clay content, the type and content of clay minerals are the most important factors affecting the imbibition capacity. The imbibed water volume normalized by the porosity increases with an increasing total clay content. Smectite and illite/smectite tend to greatly enhance the water imbibition capacity. Furthermore, clay-rich tight rocks can imbibe a volume of water greater than their measured pore volume. The average ratio of the imbibed water volume to the pore volume is approximately 1.1 in the Niutitang shale, 1.9 in the Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the Yingcheng volcanic rock, and this ratio can be regarded as a parameter that indicates the influence of clay. In addition, surfactants can change the imbibition capacity due to alteration of the capillary pressure and wettability. A 10 wt% KCl solution can inhibit clay absorption to reduce the imbibition capacity.

A model describing flowback chemistry changes with time after Marcellus Shale hydraulic fracturing

Between 2005 and 2014 in Pennsylvania, about 4000 Marcellus wells were drilled horizontally and hydraulically fractured for natural gas. During the flowback period after hydrofracturing, 2 to (7 to ) of brine returned to the surface from each horizontal well. This Na-Ca-Cl brine also contains minor radioactive elements, organic compounds, and metals such as Ba and Sr, and cannot by law be discharged untreated into surface waters. The salts increase in concentration to () in later flowback. To develop economic methods of brine disposal, the provenance of brine salts must be understood. Flowback volume generally corresponds to ∼10% to 20% of the injected water. Apparently, the remaining water imbibes into the shale. A mass balance calculation can explain all the salt in the flowback if 2% by volume of the shale initially contains water as capillary-bound or free Appalachian brine. In that case, only 0.1%–0.2% of the brine salt in the shale accessed by one well need be mobilized. Changing salt concentration in flowback can be explained using a model that describes diffusion of salt from brine into millimeter-wide hydrofractures spaced 1 per m (0.3 per ft) that are initially filled by dilute injection water. Although the production lifetimes of Marcellus wells remain unknown, the model predicts that brines will be produced and reach 80% of concentration of initial brines after ∼1 yr. Better understanding of this diffusion could (1) provide better long-term planning for brine disposal; and (2) constrain how the hydrofractures interact with the low-permeability shale matrix.

Innovative use of rate-transient analysis methods to obtain hydraulic-fracture properties for low-permeability reservoirs exhibiting multiphase flow

Multifractured horizontal wells, while enabling commercial production from unconventional gas and light-oil reservoirs, are challenging to analyze quantitatively to obtain reservoir and hydraulic-fracture properties. Production rates and flowing pressures gathered immediately after hydraulic-fracture stimulation (flowback) and over a longer time period (on-line production) can be interpreted for hydraulic-fracture properties such as fracture surface area or half-length and fracture conductivity, but dynamic fracture properties and multiphase flow during both stages of production can complicate the analysis. Recent studies have suggested that flowback data can provide early insight into these fracture properties if high-resolution fluid rates/pressures are gathered, but the physics of the process are complex, and analytic methods for interpretation are at an early stage of development. Analytic methods for longer-term production data analysis, although better established, are still limited primarily to single-phase flow and simple fracture and reservoir behavior. Rate-transient methods can be applied to both flowback and long-term production data to quantify hydraulic-fracture properties and changes in effective hydraulic-fracture length during production. For the flowback period, simplified analytic methods have been developed for before-breakthrough production of hydraulic-fracturing fluids and after-breakthrough production of hydraulic-fracture and reservoir fluids. These methods are still under development, and early applications can be illustrated. For long-term production analysis, classic rate-transient analysis techniques, such as the square-root-of-time plot, have been modified to account for multiphase flow and stress-sensitive permeability exhibited by low-permeability gas condensate and black-oil reservoirs producing below saturation pressure. A field example consisting of a multifractured horizontal well completed in a tight-oil reservoir isused to to compare hydraulic-fracture properties derived from flowback and long-term production data. Although flowback analysis yields hydraulic-fracture half-lengths consistent with hydraulic-fracture modeling results, long-term production analysis yields much smaller fracture half-lengths, possibly because of breakthrough of gas once bubble-point pressure is reached. Additional mechanisms for effective producing fracture half-length reduction can be proposed. Another important observation is that estimation of fracture properties from long-term production analysis of a reservoir producing below saturation pressure can be in significant error if the estimates are derived from techniques assuming single-phase flow. Corrections to the analytic methods for multiphase flow yield fracture half-lengths consistent with those obtained from history matching using rigorous numerical simulation. In a preliminary analysis, the techniques under development are intended to aid hydraulic-fracture evaluation and design in tight reservoirs that exhibit complex flow characteristics. Furthermore, implications of the findings will be important to assist in designing well operations to maximize well performance.

Microfiltration in recycling of Marcellus Shale flowback water: Solids removal and potential fouling of polymeric microfiltration membranes

Flowback water generated during unconventional gas extraction is of great concern due to its high total dissolved solids (TDS), radioactive elements and organic matter. Abandoned mine drainage (AMD) is a water source that is often located in the vicinity of gas wells and can be mixed with flowback water to reduce fresh water usage for hydraulic fracturing. The feasibility of microfiltration to separate solids created by mixing actual flowback water and AMD was evaluated using a bench-scale setup. Hydrophilic polyvinyldiene fluoride (PVDF) membrane with a pore size of 0.22μm was as a model polymeric microfiltration membrane.Severe membrane fouling occurred during the first 5min of filtration with one flowback/AMD mixture while no significant fouling was observed for a different mixture. It was found that the flowback water that caused membrane fouling contained stable iron-based colloids with an average particles size of 0.2μm, especially in the samples collected early in the flowback period. These colloids were not formed by mixing flowback water containing high barium concentration with AMD rich in sulfate but were originally present in the flowback water. Stability of these sub-micron colloidal particles at high ionic strength of the flowback water is attributed to organic coating on the particle surface.

Modeling Two-Phase Flowback of Multifractured Horizontal Wells Completed in Shale

Summary Early fluid production and flowing pressure data gathered immediately after fracture stimulation of multifractured horizontal wells may provide an early opportunity to generate long-term forecasts in shale-gas (and other hydraulically fractured) reservoirs. These early data, which often consist of hourly (if not more frequent) monitoring of fracture/formation fluid rates, volumes, and flowing pressures, are gathered on nearly every well that is completed. Additionally, fluid compositions may be monitored to determine the extent of load fluid recovery, and chemical tracers added during stage treatments to evaluate inflow from each of the stages. There is currently debate within the industry of the usefulness of these data for determining the long-term production performance of the wells. “Rules of thumb” derived from the percentage of load-fluid recovery are often used by the industry to provide a directional indication of well performance. More-quantitative analysis of the data is rarely performed; it is likely that the multiphase-flow nature of flowback and the possibility of early data being dominated by wellbore-storage effects have deterred many analysts. In this work, the use of short-term flowback data for quantitative analysis of induced-hydraulic-fracture properties is critically evaluated. For the first time, a method for analyzing water and gas production and flowing pressures associated with the flowback of shale-gas wells, to obtain hydraulic-fracture properties, is presented. Previous attempts have focused on single-phase analysis. Examples from the Marcellus shale are analyzed. The short (less than 48 hours) flowback periods were followed by long-term pressure buildups (approximately 1 month). Gas + water production data were analyzed with analytical simulation and rate-transient analysis methods designed for analyzing multiphase coalbed-methane (CBM) data. This analogy is used because two-phase flowback is assumed to be similar to simultaneous flow of gas and water during long-term production through the fracture system of coal. One interpretation is that the early flowback data correspond to wellbore + fracture volume depletion (storage). It is assumed that fracture-storage volume is much greater than wellbore storage. This flow regime appears consistent with what is interpreted from the long-term pressure-buildup data, and from the rate-transient analysis of flowback data. Assuming further that the complex fracture network created during stimulation is confined to a region around perforation clusters in each stage, one can see that fluid-production data can be analyzed with a two-phase tank-model simulator to determine fracture permeability and drainage area, the latter being interpreted to obtain an effective (producing) fracture half-length given geometrical considerations. Total fracture half-length, derived from rate-transient analysis of online (post-cleanup) data, verifies the flowback estimates. An analytical forecasting tool that accounts for multiple sequences of post-storage linear flow, followed by late-stage boundary flow, was developed to forecast production with flowback-derived parameters, volumetric inputs, matrix permeability, completion data, and operating constraints. The preliminary forecasts are in very good agreement with online production data after several months of production. The use of flowback data to generate early production forecasts is therefore encouraging, but needs to be tested for a greater data set for this shale play and for other plays, and should not be used for reserves forecasting.

Diagnosis of Acid Placement From Temperature Profiles

Summary Optimum fluid placement is crucial for a successful acid-stimulation treatment, both for horizontal wells where there is a broad variation of reservoir properties along the wellbore and for vertical wells with multiple zones and/or extensive productive intervals. Recently, distributed-temperature-sensing technology has enabled us to observe dynamic temperature profiles along a wellbore during and after an acid treatment. This technology allows us to monitor and evaluate treatments in real time by capturing a sequence of temperature profiles at different times and inverting temperature response to acid-injection profiles. We have developed mathematical models to simulate the temperature behavior along a wellbore, horizontal or vertical, during and just after an acid treatment. This approach couples a wellbore model and a near-wellbore formation thermal model considering the effects of both mass and heat transfer between the wellbore and the formation. The models account for all significant thermal processes involved during a treatment, including heat of reaction, conduction, and convection. An inversion procedure is applied to interpret the acid-distribution profiles from the measured temperature profiles. For horizontal wells, the results indicate that the distribution of stimulation fluid along a lateral and the effectiveness of diversion processes during an acid treatment can be quantified in real time using distributed-temperature measurements. The model shows that the relative injectivities into different zones can be interpreted from the temperature response measured during injection. For vertical wells, we have focused on diagnosing the volume of acid placed in each zone from the flowback temperature history. During the flowback period, the zones that have taken more acid volume will show more heating because of reaction and will have higher temperature when hotter fluid enters the wellbore. This provides a mechanism to quantitatively determine the acid distribution. The methods developed from this study can help to diagnose and optimize acidizing design, and improve the efficiency of acid stimulation.

Laboratory-Based Evaluation of Gas Well Deliverability Loss Caused by Water Blocking

Summary Water blocking caused by invasion of completion fluids has been suspected to reduce gas well deliverability.1–5 However, this effect has not been quantified. We report results of a laboratory program to measure the water-blocking effect in core samples from a gas field. These data were mapped to a wellbore model to make deliverability predictions. The laboratory data consist of gas flow rate as a function of injected gas pore volume for various liquids (brine, methanol, toluene, isopropyl alcohol, and brine-methanol mixtures) at two saturation states (fully saturated with liquid, and containing liquid and trapped gas). We injected over 10,000 PV of gas in each test to mimic near-wellbore conditions. The data showed that the liquid displacement regime was followed by a mass transfer regime. The wellbore model had a time varying skin to account for the cleanup of the fluid invaded ("water-blocked") region. Cleanup occurs as gas flows past this high liquid-saturated region and removes liquid by displacement and mass transfer. We used the laboratory data to relate the reduced permeability of this region to pore volumes of gas throughput. We find that any loss in gas well deliverability recovers in two phases. The first phase corresponds to fluid displacement ("flowback period") and lasts for a few days at most. The second phase is slower and can last several months. Here, evaporation causes the deliverability to slowly increase. It is in this regime that adding volatile fluids, such as methanol, to the completion brines has advantages.