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Gummy bears is one of the names for a gross mix of downhole junk that can foul a separator or clog tubing in the Woodford play in Oklahoma. The texture is often rubbery - the only connection to the gummy candy - and the color varies depending on whether the well’s output tilts toward oil or gas. These “unusual semi-solid” accumulations were described in a 2015 Halliburton paper as containing hydrocarbons, sand, iron, fine particles from clay, and sometimes a bit of friction reducer - polyacrylamide to be exact (SPE 173594). The globs generally are seen at the surface after fracturing. When they are observed downhole, they have been pushed by the well’s flow into “choke points” such as “perforations, tubing anchors, gas lift valves” downhole which are noticed when production declines, the paper said. Analysis revealed that those semi-solid amalgams contained iron, which was not in the injected fracturing fluid. While the nature of the stuff made poly-acrylamide a likely ingredient, they did not find acrylamide - the ingredient combined with polymers to make friction reducer. The paper suggested that fracturing “released materials with a strong positive charge (cations)” which were part of “a complex mixture including other solids and the acrylamide, forming a tight emulsion in semi-solid form.” The paper offered a workable description of what was going on below. But the analysis and solutions offered did not seem to make a dent in the problems that were so bad for some operators in the Woodford that they switched from friction reducer to guar to avoid the gunk. Guar, a natural product is not as effective as polyacrylamide at reducing friction. While it has long been used to thicken water-based fluids and allow them to deliver more proppant, laboratory testing concluded guar can hinder production. Substituting guar “is not ideal because the residue guar can [be left] behind on a proppant pack,” said Mark Van Domelen, vice president for technology at Downhole Chemical Solutions (DCS). The maker and supplier of fracture chemicals has been working with Ovintiv on a way to pump friction reducer without the gummy side effects. Ovintiv, formerly known as Encana, saw improved chemistry as a way to increase production from the Oklahoma acreage it acquired from Newfield Exploration. The research partners tested the widely held theory that the gunk was created by a reaction between polyacrylamide and pyrite (iron sulfide or FeS2) in fresh water and found, “When an iron source is added to the fluid a nearly instantaneous development of the accumulation material was noted,” according to their paper (URTeC 2487). A Determined Operator The partners identified the source of the obvious problem - the gummy bears - and some less obvious ones that could undercut the effectiveness of chemicals used for fracturing. One of those is the widely used practice of injecting acid on a site before it is stimulated, which is known as an acid spearhead.
Gummy bears is one of the names for a gross mix of downhole junk that can foul a separator or clog tubing in the Woodford play in Oklahoma. The texture is often rubbery--the only connection to the gummy candy--and the color varies depending on whether the well's output tilts toward oil or gas. These "unusual semi-solid" accumulations were described in a 2015 Halliburton paper as containing hydrocarbons, sand, iron, fine particles from clay, and sometimes a bit of friction reducer--polyacrylamide to be exact (SPE 173594). The globs generally are seen at the surface after fracturing. When they are observed downhole, they have been pushed by the well's flow into "choke points" such as "perforations, tubing anchors, gas lift valves" downhole which are noticed when production declines, the paper said.
Friction reducers are expected to play critical roles in fracturing, some better than others. Shale producers are belatedly realizing that there are many variables that can alter the performance of these chemicals used to reduce the power needed to hydraulically fracture a reservoir, and in higher doses, to thicken fluid, making it possible to deliver proppant more efficiently. There are wells that can justify paying more for a friction reducer formulated to stand up to difficult chemical challenges, and others that cannot. But there is no guide that describes how these key additives perform. Those who do evaluations will realize that a lot of details about friction reducers are proprietary and no industry standard provides guidance about the information needed to thoroughly assess their compatibility with reservoir conditions.
Gundogar, Asli S. (SLAC National Accelerator Laboratory / Stanford University Energy Resources Engineering) | Druhan, Jennifer L. (University of Illinois at Urbana) | Ross, Cynthia M. (Stanford University Energy Resources Engineering) | Jew, Adam D. (SLAC National Accelerator Laboratory) | Bargar, John R. (SLAC National Accelerator Laboratory) | Kovscek, Anthony R. (Stanford University Energy Resources Engineering)
Abstract Field and laboratory observations to date indicate that the efficiency of hydraulic fracturing, as it relates to hydrocarbon recovery, depends significantly on geochemical alterations to rock surfaces that diminish accessibility by partial or total plugging of the pore and fracture networks. This is caused by mineral scale deposition such as coating of fracture surfaces with precipitates, particle migration, and/or crack closure due to dissolution under stress. In reactive flow-through experiments, mineral reactions in response to acidic fluid injection significantly reduced system porosity and core permeability. The present study focuses on changes to fluid chemistry and shale surfaces (inlet and fracture walls) resulting from shale-fluid interactions and integrating these findings for an improved estimate of transport-related consequences. The reacted shale surfaces were examined by spatially-resolved scanning electron microscopy - energy dispersive spectroscopy (SEM-EDS) analysis. Importantly, inductively coupled plasma - mass spectrometry/optical emission spectroscopy (ICP-MS/OES) was utilized to probe the chemical evolution of the core-flood effluents. The three study cores selected from the Marcellus formation represent different mineralogies and structural features. In flow-through experiments, lab-generated brine and HCl-based fracture fluid (pH=2) were injected sequentially under effective stress (up to 500 psi) at reservoir temperature (80°C). SEM-EDS results confirmed by the ICP concentration trends showed significant Fe hydroxide precipitates in clay- and pyrite-rich outcrop samples due to partial oxidation of Fe-bearing phases in the case of intrusion of low salinity water-based fluids. Porosity reduction in the MSEEL (Marcellus Shale Energy and Environmental Laboratory) carbonate-rich sample is related to compaction of cores under stress due to matrix softening with substantial dissolution, and pore-filling by hydroxides, as well as barite and salts. Despite the same fluid compositions and experimental conditions used for both MSEEL samples, barite precipitation was much more intense in the MSEEL clay-rich sample due to its greater sorption capacity and additional sulfate source as well as fissile nature with multiple lengthwise cracks. ICP tests revealed time-resolved concentration trends in produced brine and reactive fluids that in turn complemented the pre-/post-reaction SEM-EDS observations.
Spielman-Sun, Eleanor (Stanford Synchrotron Radiation Lightsource) | Jew, Adam D. (Stanford Synchrotron Radiation Lightsource) | Druhan, Jennifer L. (University of Illinois at Urbana-Champaign) | Bargar, John R. (Stanford Synchrotron Radiation Lightsource)
Abstract Precipitation of secondary mineral species during stimulation is a well-recognized problem in the industry. This problem is exacerbated when "clean" brine derived from the repurposing of produced water is used as a base fluid in hydraulic fracturing fluid (HFF) formulations. Sulfate mineral scaling within the fracture spaces of the stimulated rock volume in particular is a well-known problem in combination with alkaline earth metals such as strontium (Sr), especially in the Permian Basin. To mitigate the impact of Sr mineral scaling, we address two areas of uncertainty: 1) understanding the thermodynamics/kinetics of precipitation under various ionic strengths and with/without HFF additives, and 2) determining if Sr can be removed from clean brines or whether adjustments to HFF additives can provide a mitigation pathway. Precipitation studies were conducted under different solution conditions (0 or 2 M NaCl, with and without various HFF chemicals). Solutions were combined to give different celestite saturation indexes (SI<1.0, SI≅1.0, or SI>1.0) and mixed at 80 °C for 4 days. The concentration of dissolved Sr was measured at different time points by inductively-coupled-plasma mass-spectrometry. Celestite precipitation readily occurred under all scenarios within 12 to 24 h. Results show that celestite (SrSO4) was the only Sr form that precipitated during these experiments. In an attempt to determine if cost-effective removal of Sr from clean brines for reuse is possible, several water treatment options were explored: Sr removal via the addition of calcium and barium sulfate (to precipitate/sorb Sr from solution), and the addition of illite (to sorb Sr from solution). The reaction of Sr-enriched produced water with Ca-sulfate minerals only showed a small reduction in dissolved Sr. The addition of illite also had no effect on dissolved Sr concentrations due to the high ionic strength of the solution inhibiting sorption. Overall extents of Sr reduction were not found to be cost-effective. An alternative approach to mitigating Sr mineral scaling considers whether additives, primarily persulfate, need to be adjusted/removed from HFF. The presence of the oxidizing breaker (ammonium persulfate) resulted in 2-3 times more Sr precipitation, depending on the solution ionic strength. These experimental results suggest that lowering sulfate rather than alkaline earth metals is the most impactful mitigation strategy for successful reuse of produced water in future hydraulic fracturing jobs.