Slickwater Fracturing Fluid Research Articles

Preparation and properties of amphoteric polyacrylamide/modified montmorillonite nanocomposites and its drag reduction performance

In this paper, the cation monomer, N, N’-dimethylhexadeylallylammonium bromide (DMHAAB), was prepared using N, N-dimethylhexadecyl amine and allyl bromide in a laboratory. Acrylamide (AM), sodium 4-styrenesulfonate (SSS) and DMHAAB were utilized to successfully synthesize acrylamide-based terpolymer (denoted as ASD) via redox free-radical polymerization. Surface-modified montmorillonite (O-MMT) was obtained by cation exchange reaction between pristine sodium montmorillonite (Na-MMT) and cetyltrimethyl ammonium bromide (CTAB). O-MMT was added during the copolymerization in order to prepare nanocomposites with the homogeneous dispersion of exfoliated phyllosilicates (denoted as ASD/MMT). The aqueous solution properties were evaluated by viscosimetry and rheological behavior. ASD/MMT exhibited better salt-tolerance, temperature-resistance, shear stability and viscoelasticity in comparison to ASD. In a closed loop system the drag reduction properties were measured where both ASD/MMT and ASD acted as drag reduction agent. The results indicated that drag reduction efficiency (DR) of ASD/2%MMT increased with Reynolds number (Re) rising and reached DR of 58% in high Re region at a concentration of 300 ppm, compared with 49% for ASD. The superior properties of ASD/MMT could be attributed to the contribution of delaminated nanoplatelets in polymer matrix, which improved the interaction strength of physical crosslink network to some extent. The ASD/MMT had a significant potential in slickwater fracturing fluids.

Polyacrylamide in hydraulic fracturing fluid causes severe membrane fouling during flowback water treatment

Sustainable wastewater management strategies are required to further minimize impacts of high-volume hydraulic fracturing (HVHF) as current practices such as reuse or direct disposal have long term limitations. Membranes can provide superior effluent quality in HVHF wastewater treatment, but the application of these systems is severely limited by membrane fouling. However, the key fouling components in HVHF wastewater have not yet been clearly identified and characterized. Here we demonstrate that fouling of microfiltration membranes by synthetic flowback water is mostly due to polyacrylamide (PAM), a major additive in slickwater fracturing fluids. A synthetic fracturing fluid was incubated with Marcellus Shale under HVHF conditions (80 ℃, 83 bar, 24 h) to generate synthetic flowback water. Different HVHF conditions and fracturing fluid compositions generated a fouling index for flowback water ranging from 0.1 to 2000 m−1, with these values well correlated with the peak molecular weight (MW) (ranging from 10 to 1.5 × 104 kDa) and the concentration of high MW components in the water. The lowest fouling index was observed when PAM was further degraded by ammonium persulfate under HVHF conditions, although this is infrequently used with PAM in current fracturing operations. These results highlight the importance of PAM and its degradation products in fouling of subsequent membrane systems, providing insights that can help in the development of effective treatment processes for HVHF wastewater.

Microseismic monitoring of a tight light oil reservoir: A case history in the Cardium Halo Play, Alberta

The effectiveness of hydraulic-fracturing completions in a tight-oil play is investigated by detailed interpretation of microseismicity. The microseismic programs were acquired in the Cretaceous Cardium light oil sandstone reservoirs in Alberta, Canada. Events with magnitudes between [Formula: see text] and [Formula: see text] are located by downhole monitor wells to a maximum distance of 525 m, enabling inference of the fracture wing length, height, and azimuth based on event distribution. The fracture ports, one per stage, were located in an open-hole configuration that used external packers for zonal isolation. During completions, the ports were opened with ball-actuated frac sleeves. Event distributions indicated that, in some cases, fractures grew preferentially away from the Rocky Mountain deformation front. This inferred that fracture asymmetry is independent of the position of the monitoring array, indicating that it cannot be ascribed to observation bias and suggesting that the direction of fracture growth was dominantly influenced by the preexisting stress conditions in the reservoir. The distribution of microseismicity further indicates that isolated event clusters occur 30–50 m above the reservoir. These out-of-zone events are interpreted to have occurred on unpropped fractures. In comparison with gelled oil or foamed water, slickwater fracturing fluids are shown to produce more diffuse and scattered microseismic expression accompanied by better cumulative oil production. Taken together, the results of these studies indicate that the use of slickwater fracturing fluid, along with the reduced stage spacing and tighter interwell spacing, is expected to lead to higher initial production as well as higher estimated ultimate recovery.

A New Friction-Reducing Agent for Slickwater-Fracturing Treatments

Summary Friction reducers (FRs) represent an essential component in any slickwater-fracturing fluid. Although the majority of previous research on these fluids has focused on evaluating the friction-reduction performance of chemical components, only a few studies have addressed the potential damage these chemicals can cause to the formation. Because of the polymeric nature of these chemicals—typically polyacrylamide (PAM)—an FR can either filter out onto the surface of the formation or penetrate deeply to plug the pores. In addition, breaking these polymers at temperatures lower than 200°F remains a problem. The present study introduces a new FR that replaces the linear gel with an enhanced proppant-carrying capacity and reduced potential for formation damage. Friction-reduction performance, proppant settling, breakability, and coreflood experiments using tight sandstone cores at 150°F were conducted to investigate a new FR (FR1). The performance of the new FR was compared with two different FRs: a salt-tolerant polymer that is a copolymer of acrylamide and acrylamido-methylpropane sulfonate (FR2), and a guar-based polymer (FR3). Different breakers were used to examine the breakability of the three FRs, including ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (HP), and sodium bromate (SB). The friction reduction of the new chemical was higher than 70% in fresh water or 2 wt% potassium chloride (KCl) in the presence of calcium chloride (CaCl2) or choline chloride. The presence of 1 lbm/1,000 gal of different types of breakers did not affect the friction-reduction performance. The friction reduction of 1 gal/1,000 gal of the new FR1 was also higher than that of the guar-based FR3 at a load of 4 gal/1,000 gal at the same conditions. The results show that the new FR is breakable with any of the tested breakers. Among the four tested breakers, APS is the most-efficient breaker. Static and dynamic proppant-settling tests further indicated a superior performance of FR1 for proppant suspension compared with a PAM FR (FR2). Coreflood experiments showed that FR1 did not cause any residual damage to the core permeability when APS was used as a breaker, compared with 10% and 9% damage when FR2 and FR3 were tested, respectively. Coreflood tests also showed that FR1 is breakable using SB with only 2.5% damage, whereas FR2 and FR3 resulted in 47% and 41% damage, respectively. The results also show that higher salinity does not affect the breakability of the new FR. The proposed FR shows higher friction-reduction performance and better proppant-carrying capacity with no formation damage, compared with the conventional counterparts. Hence, FR1 is a viable choice for application in fracturing formations with proppants.

Adsorption damage and control measures of slick-water fracturing fluid in shale reservoirs

Abstract The slick-water polymer adsorption damage and control measures in shale were examined using a shale pack model of the Ordovician Wufeng Formation–Silurian Longmaxi Formation in the Changning block of the Sichuan Basin. The adsorption law of slick water under different displacement time, concentrations, pH values and temperatures of polymer were tested by traditional displacement experiment and UV-Vis spectrophotometer. The adsorption equilibrium time was 150 min, the amount of adsorption was proportional to the concentration of the polymer, and the maximum adsorption concentration was 1 800 mg/L. With the increase of pH value, the adsorption capacity decreased gradually, the adsorption capacity increased first and then decreased with the increase of temperature, and the adsorption capacity was the largest at 45 °C. The adsorption patterns of polymers on shale were described by scanning electron microscopy and magnetic resonance imaging. It is proved that the adsorption of polymer on shale led to the destruction of the network structure of anionic polyacrylamide molecules, and the shale adsorption conformation was characterized qualitatively. Finally, according to the adsorption law and adsorption mechanism, it is proposed to reduce the adsorption quantity of polymer on shale surface by using hydrogen bond destruction agent. The effects of hydrogen bond destruction on four kinds of strong electronegative small molecules were compared, the hydrogen bond destroyer c was the best, which lowered the adsorption capacity by 5.49 mg/g and recovered permeability to 73.2%. The research results provide a reference for the optimization of construction parameters and the improvement of slickwater liquid system.

Effect of salt on the performance of drag reducers in slickwater fracturing fluids

Slickwater fracturing has historically utilized freshwater as a base fluid and Friction Reducer (FR) as a main additive to reduce the friction pressures in the wellbore and within the fractures. This technology is getting challenging because of the limited sources of freshwater, the increased flowback fluid disposal costs, and stricter disposal regulations. The oil and gas industry has been trying to optimize the reuse of slickwater fracturing flowback fluids to help reduce the use of freshwater. The flowback contains mainly water, salts from formation water, and chemicals that were introduced from the hydraulic fracturing.The main objective of this study is to experimentally investigate effects of salinity on the performance of FRs for the purpose of reusing the flowback. The Hydraulic Testing Facility was used to perform hydraulic tests to investigate the effects of salinity on the performance of FRs. Three commercial FRs, namely anionic Friction Reducer A (FR-A), anionic Friction Reducer B (FR-B), and cationic Friction Reducer C (FR-C), were used to conduct the tests. The concentration of the FRs was varied from 0.5 to 1.2 liters/m3 of water (0.5–1.2 gallons per thousand gallons of water). Sodium Chloride and Calcium Chloride at different concentrations were added to the solution to study the salinity effects. In addition, multiple rheological tests were executed to understand the effects of salinity on the rheological properties of slickwater.The results revealed that the anionic FR-B performs better than the anionic FR-A in fresh water. The percent friction reduction of FR-B and FR-A at 0.478 g/L (4 pptg) in fresh water were about 60% and 40%, respectively. In addition, the performance of FR-B is less sensitive to salts than that of FR-A. Therefore, It is recommended to add 0.478 g/L (4-pptg) of FR-B directly into the flowback, which has the total dissolved solid values of 100000 mg/L or less without the need of pretreatment to achieve the percent friction reduction of 40% or higher. Cationic FR-C performed the best when compared with anionic FR-A and FRB at high salinity, e.g. 200000-mg/L total dissolved solid. Under the testing conditions, a conservative conclusion may be drawn that cationic FRs may perform better with the presence of salts than that of anionic FRs.

Chemical Degradation of Polyacrylamide during Hydraulic Fracturing.

Polyacrylamide (PAM) based friction reducers are a primary ingredient of slickwater hydraulic fracturing fluids. Little is known regarding the fate of these polymers under downhole conditions, which could have important environmental impacts including decisions on strategies for reuse or treatment of flowback water. The objective of this study was to evaluate the chemical degradation of high molecular weight PAM, including the effects of shale, oxygen, temperature, pressure, and salinity. Data were obtained with a slickwater fracturing fluid exposed to both a shale sample collected from a Marcellus outcrop and to Marcellus core samples at high pressures/temperatures (HPT) simulating downhole conditions. Based on size exclusion chromatography analyses, the peak molecular weight of the PAM was reduced by 2 orders of magnitude, from roughly 10 MDa to 200 kDa under typical HPT fracturing conditions. The rate of degradation was independent of pressure and salinity but increased significantly at high temperatures and in the presence of oxygen dissolved in fracturing fluids. Results were consistent with a free radical chain scission mechanism, supported by measurements of sub-μM hydroxyl radical concentrations. The shale sample adsorbed some PAM (∼30%), but importantly it catalyzed the chemical degradation of PAM, likely due to dissolution of Fe2+ at low pH. These results provide the first evidence of radical-induced degradation of PAM under HPT hydraulic fracturing conditions without additional oxidative breaker.

XFEM modeling of multistage hydraulic fracturing in anisotropic shale formations

The aim of the present study is to help understand hydraulic fracture propagation in shale formations through numerical simulations. The hydraulic fracture propagation regime in shale is analyzed considering the anisotropic nature of the shale rock formation and slick-water fracturing fluid. It is determined that the dominant mechanism of hydraulic fracture propagation is the so-called transitional regime that is characterized by a negligibly small fluid lag region and zero fluid front pressure. For the modeling of the hydraulic fracture evolution over time, we assume orthotropic linear-elastic rock media and that the flow of the fracturing fluid is governed by the Reynold's lubrication equation. For the discretization of the coupled solid-fluid equations within the 2D plane-strain context we use the extended finite element method for the rock media and the finite volume method for the lubrication equation. The problem of the hydraulic fracture evolution over time is modeled as stable quasi-static crack growth where time is the result of upholding the mass conservation principle between the fluid inflow and the crack volume. The Picard iterative approach is used to solve the discrete non-linearly coupled solid-fluid equations. Our model is verified against several analytical solutions. Subsequently, a five-stage hydraulic fracturing problem is simulated to study the interactions between the different fractures. Results show that the on-going hydraulic fractures are attracted by the pre-existing hydraulic fractures as a result of the change of the local stress field relative to the initial in-situ stress field. For the cases considered, fracture deflections are found to be most extensive with decreasing fracture spacing and in-situ stress difference, but insensitive with the increasing the ratio of Young's moduli.

Drag reduction behavior of hydrolyzed polyacrylamide/xanthan gum mixed polymer solutions

Partially hydrolyzed polyacrylamide (HPAM) as the main component of slickwater fracturing fluid is a shear-sensitive polymer, which suffers from mechanical degradation at turbulent flow rates. Five different concentrations of HPAM as well as mixtures of polyacrylamide/xanthan gum were prepared to investigate the possibility of improving shear stability of HPAM. Drag reduction (DR) measurements were performed in a closed flow loop. For HPAM solutions, the extent of DR increased from 30% to 67% with increasing HPAM concentration from 100 to 1000 wppm. All the HPAM solutions suffered from mechanical degradation and loss of DR efficiency over the shearing period. Results indicated that the resistance to shear degradation increased with increasing polymer concentration. DR efficiency of 600 wppm xanthan gum (XG) was 38%, indicating that XG was not as good a drag reducer as HPAM. But with only 6% DR decline, XG solution exhibited a better shear stability compared to HPAM solutions. Mixed HPAM/XG solutions initially exhibited greater DR (40% and 55%) compared to XG, but due to shear degradation, DR% dropped for HPAM/XG solutions. Compared to 200 wppm HPAM solution, addition of XG did not improve the drag reduction efficiency of HPAM/XG mixed solutions though XG slightly improved the resistance against mechanical degradation in HPAM/XG mixed polymer solutions.

New integrated model of the settling velocity of proppants falling in viscoelastic slick-water fracturing fluids

An experimental study was performed to understand the proppant settlement in slick-water fracturing fluids, the velocity distribution was statistically analyzed, and a comparison of the measured results and those predicted values was conducted. The spread of the proppant settling velocity of mesh 20/40 is large, and as the proppant size reduces, the proppant settling velocity distribution tends to be concentrated for mesh 40/70. The actual size of the proppant is larger than its sieving diameter. When proppants settle in glycerol solutions, the measured settling velocity is 1.57 times the predicted value. The relationship between the proppant settling velocity and the sieving diameter was studied, and the elasticity effect of slick-water on the proppant settling velocity was investigated. The experimental results demonstrate that the proppant settling velocity increases linearly with the square and the (n+1)/nth power of the sieving diameter in glycerol solutions and slick-water, respectively. The proppant settling velocity increases with the slick-water elasticity; this phenomenon is more pronounced for large proppant particles. An integrated settling velocity model was established based on the proppant sieving diameter; this model can be easily used by petroleum engineers.

Recent advances on friction reducer for slickwater fracturing of shale gas reservoirs

The slickwater fracturing of shale gas reservoirs is a novel fracturing techniques developed in recent years and the slickwater fracturing fluid is a key technique. Compared with the traditional gelatinous fracturing fluid, the slickwater fracturing fluid has the advantages of high efficiency and low cost which has been widely used in the completion and production of shale gas reservoirs. As the core of the slickwater fracturing fluid, the friction reducer ultimatly determine the fluids performances. In this review, the reported friction reducer and our own work are summarized and discussed, and the development trends are evaluated.

Mobile Mixer Adds Dry Friction Reducer to Fracturing Fluid at the Wellsite

Technology Update A mobile system has been developed that mixes consistent solutions of powder-based friction reducers (FRs) at the wellsite and adds them to hydraulic fracturing fluid. The use of the system has achieved reductions in fracture stage cycle times of as much as 10% and significant cost savings, compared with the convention-al use of oil-based liquid emulsion FRs in slickwater fracturing fluids. In addition, the use of powder-based FRs reduces the potential of the FR solution freezing, settling, or gelling and eliminates the hazard of liquid FR spillage in work areas. Water-soluble dry polyacrylamide can be used as an FR, with the selection of a polymer dependent on water quality. Dry FRs can perform in waters ranging from fresh water to high-brine produced water. The challenge to developing the use of dry FRs in fracturing fluid was the ability to hydrate them on a treatment site. The PowderFrac mobile mixing and feeding system developed by SNF has performed successfully in the field since its initial deployment in the Barnett Shale of Texas during 2011. The system provides onsite storage, hydration, and dose control of the powder FRs. The mobile unit enables well operators to reduce logistics and labor costs, and the chemistry of the dry FR solutions is also less costly. Deployment of the mobile unit does not require the modification of equipment or infrastructure at the fracturing site. The unit was designed and built with field replaceable parts to ensure prompt, cost-effective vehicle maintenance while deployed. The equipment includes a patented Polymer Slicing Unit (PSU) for rapid hydration of the dry FR. The PSU can operate at treatment rates up to 120 bbl/min. Additional equipment consists of two solution tanks, a 12,000-lbm dry storage container, a horizontal screw conveyor, water filter pots, water pumps, FR solution pumps, and a self-contained generator system that can be fueled by an onboard tank or the saddle tank of the tractor. Safe deployment and operation is a crucial part of the unit’s design. All electronics capable of data recording can perform reporting and analysis. The mobile unit, 45 ft in length, requires no special transport permits and can be refilled with dry powder FR by a powder bulk truck. The friction reduction from a polyacrylamide will be affected by water quality and salinity and any other additives in the fluid that interact with the polymer. Concentrations of FR are adjusted during the treatment to lower or raise the pumping pressure.