Low injected fracturing fluid recovery has been an issue during flowback period that is highly impacted by the fracture closure behavior. Although existing flowback models consider fracture closure volumetrically, they do not represent the true situation of non-uniform fracture closure. In this paper, we proposed a coupled geomechanics and fluid flow model for early-time flowback in shale oil reservoirs. The fluid flow model is coupled with an elastic fracture closure model through finite element methods. In this study, three stages are modeled: fracture propagation, well shut-in and flowback. Cohesive Zone Method (CZM) has been used for modeling fracture propagation. The presented model distinguished the propped part from the unpropped part of the fracture. At the beginning of flowback, the proppants may not be completely compacted in early shut-in time. Thus, permeability evolution during closure is tracked using a smooth permeability transition function. The numerical results have shown that fracture closure during the flowback period is often not uniform. While the uniform fracture closure leads to maximum fracturing fluid recovery, an aggressive pressure drawdown strategy may damage fracture connectivity to the wellbore. An integrated flowback model enables modelling nonuniform fracture closure in a complex fracture network. This study highlights that by choke/pressure drawdown management, operators can influence fluid recovery and even maintain high fracture conductivity. Furthermore, the methodology presented in the paper can also be used for inverse analysis on early flowback data.

The present study used the workflow presented in Al-Ameri et al. (2018a , 2018b ) to evaluate the impact of the fracturing fluid imbibition on the near fracture face shale matrix. Al-Ameri et al. (2018b) used carbonate-rich outcrop shale core samples that had very low and no clay content. However, in this workflow, core samples from the Barnett reservoir that had an abundant amount of quartz and clay were used. The primary aspect of the current study is to investigate the mutual effect of the shale rock petrophysical properties and the polymer adsorption; moreover, the effect of the shale mineralogical composition on the rock prone to adsorb polymer. The effect of the non-ionic surfactant on the imbibition rates, and also the anisotropy on the rock ability for polymer adsorption were also investigated. The results of this workflow were compared to the Marcellus samples results presented in Al-Ameri et al. (2018b) . The workflow incorporates conducting three systematic imbibition experiments for a same shale core sample using brine, slickwater, and brine again. The sample brine permeability was measured before and after the imbibition experiments using a constant rate steady-state permeability setup. The results showed that the polymer adsorption reduces the brine spontaneous imbibition volumes. Moreover, the shale petrophysical properties could dominate the polymer adsorption more than the mineralogical composition. Adding a non-ionic surfactant to the slickwater enhanced the imbibition rate considerably into both of the Barnett and Marcellus shale samples, and that improves the fluid flowback in these shales. The bedding planes and their orientation are among the factors that control the effect of the polymer adsorption on the fluid imbibition rate. The more obvious are the bedding planes, the higher impact of the polymer adsorption on the fluid imbibition rate. However, the petrophysical properties have more effect on the shale prone to adsorb the polymer than the bedding plane orientation. The effect of the polymer adsorption slightly increased the capillary pressure curve. However, as the porosity and permeability increase, the effect of the polymer adsorption on the capillary pressure increases. In comparison to the Eagle Ford shale, the Barnett and Marcellus shales had lower capillary pressure, and that could be one of the reasons of their higher fluid flowback. The impact of the polymer adsorption on the water relative permeability was less for the Barnett sample in comparison to the Marcellus sample because of its lower porosity and permeability.

In the late summer of 2009 an American oil and gas producer teamed up with a Canadian pumping service company and performed a series of Liquified Petroleum Gas (LPG) fracturing treatments in Pennsylvania's Marcellus Shale. A total of four stages were pumped on three different vertical wells in three different counties Centre, Lycoming, and Indiana. Questions surrounding damage associated with pumping large volumes of fresh water in nano-to-micro Darcy shale along with environmental pressures about water supply and disposal led to consideration of an alternative, non-aqueous fracturing fluid. A hydraulic fracturing process utilizing 100% LPG as a fracturing fluid to carry proppant into shale or a coal seam or other water sensitive pay zone was developed. The new LPG fluid could be easily viscosified with oil gelling chemicals allowing for excellent proppant transport. LPG was an appealing choice of fracturing fluid because its phase behavior in the Marcellus Shale at bottomhole conditions would theoretically render it non-damaging. The fracturing process brought sand into the gelled LPG so that it could be pumped under high pressure and into created fracture geometry in a pay zone. With respect to well cleanup post-frac LPG held the promise of greater cleanup and improved effective fracture half-lengths. This paper will provide details about the LPG fracs and the resulting production response using a mix of readily available public domain information and information obtained by service providers or vendors. Initially, it was author's intention to use only public data but changes in the local market made access to more information available. A comparison of LPG fracturing treatments with slickwater treated wells will be shown for two of the three wells. Concluding remarks will discuss the current state of LPG fracturing in North America and a possible explanation for production results that did not meet expectations.

In multi-fractured horizontal wells (MFHW), fracture properties such as permeability and fracture half-length significantly deteriorate during early production, which negatively affects gas production from shale reservoirs. Therefore, it is crucial to evaluate the temporal changes in fracture properties based on production data. This paper presents a workflow in which both flowback and long-term production data are used to quantitatively evaluate hydraulic fracture closure and changes in the fracture properties. In addition, we develop a two-phase semi-analytical model based on rate transient analysis (RTA) that assumes boundary dominated flow during the flowback period. The proposed workflow consists of three steps. First, we used the flowback data to calculate fracture properties, such as initial fracture permeability and fracture half-length, by employing the two-phase semi-analytical model. Then, we calculated initial fracture permeability by using a single-phase bilinear flow model as well as the fracture half-length and matrix permeability by using a single-phase linear flow model from the long-term gas production data. These models consider pressure dependency of permeability. Last, we compared the results that are calculated from both flowback and long-term production data to evaluate fracture closure and its effects on fracture permeability. We validated the semi-analytical flowback model and the workflow against numerical simulations. The results show that the developed model is capable of predicting fracture properties and evaluating fracture closure. Furthermore, the proposed workflow provides quantitative insights on the performance of fracture stimulation and is able to closely estimate permeability modulus using flowback and long-term production data instead of conducting laboratory experiments.

Throughout fracturing treatment, millions of gallons of water are injected, but commonly less than 50% is recovered after stimulation. This study was constructed to evaluate the impact of the fracturing additives on the fluid flowback and fluid loss during hydraulic fracturing. Different pad fluids types were considered including; friction reducer fluid, friction reducer with a non-ionic surfactant fluid and 3 wt% HCl acid. Flooding experiments were conducted for core samples from the Eagle Ford outcrop to measure the brine permeability, time of breakthrough and water relative permeability. The measurements were performed for intact samples and also after flooding the samples with the fracturing fluids. A simulation sector modeling for a hydraulically fractured vertical well in the shale formation was constructed to investigate the effect of the fracturing additives on the fluid flowback and fluid loss during hydraulic fracturing. A sensitivity analysis was considered to study the effect of the formation capillary pressure and reservoir pressure on the fluid flowback and fluid loss due to counter-current capillary imbibition. The study results showed that the fluid saturation in the near fracture face shale matrix is highly reduced by the effect of the high capillary pressure. Therefore, the fluid had not flow back from the near fracture face matrix. Moreover, adding a non-ionic surfactant to the friction reducer pad fluid or using 3 wt% HCl increased the fluid loss during pumping and the fluid imbibition during shut-in, flowback, and production. Therefore, the dilute HCl acid and small well shut-in times are recommended when no flowback occurs from the near fracture face matrix due to low fluid saturation. The fluid loss from the near fracture face region due to counter-current capillary imbibition reduced the effect of the fluid saturation on the gas production. However, the high fluid saturation and the polymer adsorption may cause water blocks. Thus, reducing the gas production or leading to a complete gas block. For shales with moderate capillary pressure, a flowback from the near fracture face matrix has occurred. Hence, the friction reducer with a non-ionic surfactant fluid and 3 wt% HCl enhanced both of the fluid loss due to counter-current capillary imbibition and the fluid flowback. However, a non-ionic surfactant and long shut-in time are recommended for the hydraulic fracturing. Shales with low reservoir pressure had less fluid flowback and more fluid loss. To minimize the fluid loss during pumping and to overcome the water block problem, it is recommended to use a friction reducer fluid in the pad stage while injecting a non-ionic surfactant or dilute acid during the subsequent fracturing steps.

Volume and salt concentrations in Marcellus flowback water depend on geology, drilling and completions, stimulation and flowback operations. Recent studies include evaluations of geochemical origins based on the compostition concentrations, flowback sampling analysis and numerical studies. However, an in-depth understanding of chemical compositions as well as the changes of compositions is still needed. In this paper, we will first review the literature related to flowback water in Marcellus shale gas wells to fully understand the chemistry, geochemistry, and physics governing a fracture treatment, shut-in, and flowback. We will then gather all public and in-house flowback data, named as 3-week or 3-month flowback in this work, to build a data set of flowback water compositions. After data screening, we will then analyze this composition database using four different methods: geographical, changes over time, linear regression, clustering and multi-variable analysis. New understandings such as the magnitude and prevailing trends of concentrations for target constituents as well as the correlations among flowback compositions, the differentiation between early and late time flowback water were obtained and explained on the basis of geochemistry and physics. Guidelines for a comprehensive sampling protocol will be provided based on our analysis.

Friction reducers (FRs) are an important component for slickwater hydraulic fracturing applications. To continue to effectively treat multiple clusters in longer laterals, even for stages out near the toe area, a robust FR system is typically required to overcome pipe friction. Additionally, it is imperative to be able to use one single FR system throughout the entire treatment that can tolerate various water sources of varying salinity up to 300,000 ppm. This paper discusses the field trials of a new salt-tolerant FR system in the Marcellus shale. A three-well trial program was initiated in the Marcellus. Various water sources with varying salinities were used with up to 100% re-use of produced water. The operator had not been able to keep the surface treating pressure between 8,000 and 8,500 psi using a standard anionic FR, which typically resulted in a lower pumping rate of less than 100 bbl/min; the first few stages using the standard FR in these wells indicated this was the case. After switching to the new FR, however, the pumping pressure immediately dropped to below 8,500 psi and the pumping rates were increased and maintained at 100 bbl/min. This new salt-tolerant FR system consists of a water-in-oil cationic polymer and an inverter. Unlike other FRs, the distinctive advantage of the new FR is that the ratio between polymer and inverter can be readily adjusted on the fly to achieve maximum friction reduction. During the pumping operations, it was demonstrated that the inverter was sufficiently quick to invert and release the polymer from oil to water, and the cationic polymer was extremely efficient at reducing additional pipe friction, even with severely impaired water. Additionally, the use of a single FR reduces inventory stock and simplifies on location quality assurance of material usage.

This paper discusses design considerations to increase the estimated ultimate recovery (EUR) on underperforming wells in a refracturing scenario. A method for, and case histories of, using an environmentally acceptable, self-removing particulate diverter that has proven to be successful in the refracturing efforts of horizontal unconventional reservoirs are provided. This method is typically chosen for its low cost, self-assembly, and self-removal. An outline of the design process for refracturing and post-refracturing procedures is included. The ability to add reservoir contact, restore conductivity, remediate blockage, and address depleted reservoir pressure make this technique desirable. Different strategies can be applied when using this technique and are typically customized to the particular candidate well selected for the refracturing treatment. The treatment designs for the wells discussed in this paper were designed to increase EUR. Candidate wells for refracturing typically fall into one or more categories: understimulation occurred in the original completion, production damaging mechanisms are present, a low investment lease retention strategy was originally required, or a pressure-sink mitigation strategy is necessary for infill completions. Candidates in this paper fall into the understimulated category. A typical procedure consists of casing inspection, wellbore cleanout, possible addition of perforations, and flowback considerations. In this study, different Haynesville shale refracturing treatments, results, and diagnostics are compared. The evolution of treatment design components, such as carrier fluid, fluid volume, proppant volume, and diverting methodology, is explained. The results and underlying theory of these changes are outlined. Pre/post-treatment production is compared, along with treatment pressure trend analysis and microseismic data. Although performing secondary stimulation treatments is becoming more common, the industry's focus on improving production decline curves has led to a surging interest in refracturing horizontal unconventional reservoirs. Decline rates in unconventional reservoirs tend to be more rapid compared to conventional reservoirs because of their ultralow permeability, limited reservoir contact, and original completion strategy. Refracturing of these reservoirs enables the recovery of hydrocarbons trapped by these restrictions.

Abstract This paper presents long-term follow-up results from post-fracture and post-refracture deliverability testing for 56 gas storage wells. The wells studied include 32 injection/withdraw (IW) wells hydraulically fractured with surface modification agent (SMA) applied to the proppant and 24 IW wells hydraulically fractured without SMA applied to the proppant for sand flowback control. Deliverability sustainability results previously presented1 will be updated for these treatments from a 6- to a 9-year period. The results will include analysis from deliverability data for SMA-treated and non-SMA-treated wells over six to nine IW cycles. Three wells of the original group of 24 wells previously fractured without SMA were refractured using SMA. In the original study, a number of wells were fractured without using SMA proppant. These earlier stimulation treatment wells suffered some operational problems and the need for proppant flowback control became apparent. The addition of SMA to fracture treatments reduced operational problems related to produced sand and fracture treatments improved deliverability. The wells that included a SMA now have been through six to seven complete pressure cycles and the long-term effects of sand flowback and well performance can be compared. The results of this updated study show that SMA injected with the proppant helps reduce operational problems in gas storage fields by reducing proppant flowback. In addition, analysis of SMA fractruring treatments in gas storage wells typically show no detriment to long-term performance. In addition, SMA can improve results from refracturing. Introduction The gas storage industry has recognized that storage well and storage field performance declines over time. In a 1993 study, the Gas Research Institute (GRI) determined that, on average, the storage industry loses over 5% of its deliverability annually.[2] Some fields or types of fields may naturally maintain deliverability better than others. The operator performs various types of well work in annual programs to combat deliverability losses. The most effective means of maintaining existing levels of deliverability in many fields is to treat wells with hydraulic-fracturing treatments (fracture jobs). Background The operator owns and operates 36 underground gas storage fields. Many of the fields have been continuously operated for 50 years or more and are regulated by the Federal Energy Regulatory Commission (FERC). To expand deliverability, or perform many other types of well, pipe, or compression construction, the operator must first obtain approval from the FERC. Additionally, the operator should maintain existing levels of deliverability because all deliverability is under contract to various customers. The deliverability is aggregated over all 36 fields so that a customer does not contract deliverability from any specific field. The results presented in this study are from wells that were either part of two expansion projects between 1997 and 1999 or annual deliverability maintenance programs. With 36 storage fields, conducting well workovers in every field each year makes little sense. Instead, work is grouped into programs to reduce overall cost and environmental impact. A 1996 deliverability maintenance program resulted in subsequent operational complications from produced proppant and led to the decision to begin including a proppant flowback control agent to each treatment. In 1996, hydraulic-fracture treatments were pumped in 8 wells in one field that had only 22 active injection/withdrawal wells, equaling more than one third of the field in a 1-year period. Meanwhile, pipeline construction caused the field to remain shut-in almost 2 months past the start of the traditional withdrawal season. The field was brought online during the peak of the heating season, holding near-maximum volumes. The field was flowed into the field line at relatively high rates to return to its expected volume position, resulting in some proppant production. Proppant reached the slug catcher and eroded some fittings in the dump flow control equipment.

Abstract Abstract This paper presents post-fracture deliverability results for 56 gas -storage wells over a two–to five-year period. Of the wells studied, 32 had a surface modification agent (SMA) applied to the proppant during the hydraulic fracturing treatment. The other 24 wells included in this study had no additives applied to the proppant for sand flowback control. The deliverability results from actual flow tests are used to evaluate how absolute open flows (AOF) held up over multiple injection and withdrawal cycles involving significant pressure differentials. The results are compared for the large data sets of wells that did and did not include the SMA in the fracture treatment. In general, the data set for wells that did not include an SMA have been through four or five complete pressure cycles. After some operational problems, the need for proppant flowback control became apparent, and later frac treatments usually included the SMA. The wells that included a SMA have been through two or three complete pressure cycles. This study was completed to alleviate the operators concern about the long-term impact of the SMA on the well performance. While the SMA effectively achieved the shortterm goal of proppant-flowback control, the operator was concerned that the fracture might be more prone to a reduction in conductivity or simple clogging. Typically, a new product or process gets a lot of attention and study. Many times the well results are tracked only for a year or less and the product or process becomes common or discarded. Longer-term studies on a product or process are less common, perhaps due to time, manpower, cost constraints, personnel changes, and a variety of other reasons. Over time, information can easily get buried in a sea of data. Wells using the once-new product or process are forgotten unless a serious problem occurs. The reason the product or process was first used may even be forgotten if it solved the problem. While results may vary from formation to formation, this longer-term look at the results of SMA, injected with the proppant, should help fracture treatment designers convince the skeptics that proppant-flowback control can achieve its immediate objective and match or exceed long-term performance expectations. Introduction The gas-storage industry has recognized that storage-well and storage-field performance declines over time. In a 1993 study, the Gas Research Institute (GRI) determined that, on average, the storage industry loses over 5% of its deliverability annually. 1 Some fields or types of fields may naturally maintain deliverability better than others. The operator performs various types of well work in annual programs to combat deliverability losses. The most effective means of maintaining existing levels of deliverability in many fields is to treat wells with hydraulic fracture treatments (fracture jobs). Background The operator owns and operates 42 underground gas-storage fields. Many of the fields have been continuously operated for 50 years or more and are regulated by the Federal Energy Regulatory Commission (FERC). To expand deliverability, or perform many other types of well, pipe, or compression construction, the operator must first obtain approval from the FERC. Additionally, it should maintain existing levels of deliverability because all deliverability is under contract to various customers. The deliverability is aggregated over all 42 fields so that a customer does not contract deliverability from any specific field.

Abstract Sand flowback can be a big problem in high rate gas wells. Sand can quickly erode chokes, valves and other surface equipment creating potentially dangerous situations for the gas well operating and pipeline companies. In 1998 and 1999 several different sand flowback or backflow control methods have been applied in Columbia Gas Transmission Company's Rockport Storage Field. Deformable particles are the latest innovation for controlling sand flowback. Unlike curable resin coated sands and tacky surface-modification agents, deformable particles differ in that they do not "glue" the sand pack in place, but rather mechanically hold it together by dimpling under stress and physically holding adjacent grains of sand firmly in place. A modest weight percentage of deformable particles can easily lock the sand pack in place, resisting the forces brought to bear by gas and fluid flow within the fracture. The Oriskany Sandstone in the Rockport Storage Field can be classified as a highly permeable formation capable of a withdrawal rate greater than 40 MMSCFD. Stimulation treatments are routinely pumped to improve the Oriskany's deliverability back to original levels following workover operations. Prior to running deformable particles for sand flowback control, tacky resin-like chemicals and curable resin coated sand were pumped to alleviate the problem. Introduction Sand or proppant flowback can result in higher operating costs due to erosion of tubulars, surface chokes, lines and valves, workovers to repair or replace downhole pumps, sand fill cleanout and production facility damage. A loss of near wellbore fracture conductivity is also a definite possibility. All of these in turn can lead to reduced production and heightened safety concerns.1,2 Sand control techniques are not normally needed on wells fractured in the Northeast United States. Indeed, the sand or fines that flow back after hydraulic fracturing operations most often is crushed fracturing sand.3 There are exceptions like Michigan's Antrim Shale where operators have struggled for more than a decade with fracturing sand flowing back during the dewatering process necessary before gas production begins. Tailing-in with 12/20 sand has historically been the first action taken in Appalachian Basin oil & gas fields where sand flowback became an issue. The logic was that the larger and heavier 12/20 sand grains would be more difficult to flow out of the well than the smaller, lighter 20/40 sand. While that is true, there are other processes at work here that can lead to failure of 12/20 sand to prevent 20/40 sand from flowing back after a treatment. In a laboratory API conductivity cell one can easily demonstrate that a sand pack of 12/20 sand resists movement better than 20/40 sand. But consider a well with a large perforated interval where some of the perforations have prematurely screened out using the smaller sand prior to the addition of the larger sand at the blender. These packed-off perforations are more apt to freely give back sand during the post-frac clean up and the producing life of the well. In the case of dynamic sand settling or banking during the fracture treatment, the larger sand may be deposited on top of the bed of smaller mesh sand. Perforations below the larger/smaller sand contact boundary within the perforated interval may give up sand when the fluid and gas velocity through this portion of the sand bed reaches some critical point.

This paper was prepared for presentation at the 1998 SPE Eastern Regional Meeting held in Pittsburgh, Pennsylvania, 9-11 November 1998.

SPE Members Abstract The Antrim shale in the Michigan Basin has been a horizon of much interest to operators in recent years. However, sand flow back into tubing and casing sometimes impedes well production by plugging artificial lift pumps used to unload water from the Antrim plugging artificial lift pumps used to unload water from the Antrim formation. This paper explores a way to control sand flowback in a well during production by placing epoxy-coated sand in the fracture. A stream of catalyzed liquid epoxy resin is added to the blending tub containing surfactant, fracturing sand, and fracturing gel to achieve the processes. Introduction In Antrim shale, a conventional completion and production technique involves fracture stimulating the Antrim and then producing Antrim shale gas and water naturally through tubing producing Antrim shale gas and water naturally through tubing placed in the well before or after stimulation. placed in the well before or after stimulation. Some operators have used artificial lifting techniques to produce water in Antrim wells. Sometimes artificially lifting produce water in Antrim wells. Sometimes artificially lifting water from the Antrim formation can enhance gas production if sand does not flow back into the wellbore during lifting. (For example, if a well being produced at 50 mcf/d under 300 psi (700 ft water) hydrostatic backpressure has the deliverability to produce gas from natural fractures and desorption processes, the production at 15 psi will be near 1000 mcf/d.) Producing at the lowest production at 15 psi will be near 1000 mcf/d.) Producing at the lowest possible pressure enhances desorption production. possible pressure enhances desorption production. If sand does flow back into tubing and casing, it may plug the pumps used to lift the water from the formation and cause serious pumps used to lift the water from the formation and cause serious problems. Sand flowback during production can be controlled by problems. Sand flowback during production can be controlled by placing a high-strength epoxy consolidated sand pack in the placing a high-strength epoxy consolidated sand pack in the formation. Liquid epoxy resin is added to the gel stream to coat proppant without disturbing the in-progress fracturing treatment proppant without disturbing the in-progress fracturing treatment The resin attaches itself to the sand grains and hardens to form a highly-permeable, consolidated fracture bed. This consolidate fracture bad helps minimize sand flowback into a wellbore during flowback and production. This paper presents techniques for using resin-coated sand to help prevent proppant flowback and describes the results in case histories. BACKGROUND INFORMATION This section describes some of the general characteristics of Devonian shale, particularly the Antrim shale, and reviews briefly the history of production from the Antrim formation. Devonian Shale Characteristics The Devonian shale in the eastern United States includes the Chattanooga shale in Alabama and northern Kentucky; the New Albany shale in Indiana, northwestern Kentucky, and Illinois; the Ohio shale in Ohio; the Antrim shale in Michigan; and the Kettle Point shale of southern Ontario, Canada (Figure 1). These shales Point shale of southern Ontario, Canada (Figure 1). These shales consist of thick, interbedded, light gray-green silty shales, and black organic-rich shales. Typical Devonian shale characteristics are listed in Table 1. Production is characterized by two flow regimes. Initial production is controlled by depletion of natural fractures; later production is controlled by depletion of natural fractures; later production is controlled by desorption and diffusion out of the production is controlled by desorption and diffusion out of the matrix. Thus the dual flow regime typically has initial flush production followed by low-rate, long-life production. production followed by low-rate, long-life production. The Antrim shale of Michigan is correlated with the Chattanooga shale of Alabama and northern Kentucky; the New Albany shale of Indiana, northwestern Kentucky, and its stratigraphic equivalent in Illinois; the Ohio shale is described as a dark gray shale in the lower part. P. 71