Comparative Study of Flowback Analysis Using Polymer Concentrations and Fracturing-Fluid Tracer Methods: A Field Study

Abstract

Summary This paper compares flowback efficiencies using polymer concentration and frac fluid tracer methods. Results are presented for the flowback efficiency of each frac fluid segment using non-radioactive chemical frac tracers injected in a well, along with the results for the total flowback efficiencies using polymer concentration and frac fluid tracer analysis methods. Two wells were fraced and traced with various chemical frac tracers. Upon commencing flowback, samples of produced aqueous fluid solution were collected according to a pre-designed sampling schedule that lasted for 72 hours. Samples were analyzed for tracer, polymer, calcium, potassium, sodium, and chloride concentrations. With the use of the mass balance technique, the total flowback volume and flowback efficiency for each fluid segment were calculated by use of the tracer method. In addition, total flowback and flowback efficiency were calculated by use of both polymer concentration and tracer methods. To better evaluate and compare the results of polymer concentration and frac fluid tracer analyses, dynamic fluid leakoff tests were conducted in a laboratory environment by use of both low and high permeability core samples. Detailed laboratory and field results are presented along with a comparison of flowback results from both polymer concentration and frac fluid tracer methods. Introduction Chemical frac tracers (CFT) are from the family of halogenated organic acids and were originally developed in an effort to bolster the level of understanding regarding the dynamics of hydraulic fracture placement, subsequent fluid flowback and proppant bed cleanup. Borrowing from many years of experience with interwell tracing in which non-radioactive chemical tracers have been successfully used to evaluate interwell communication, several groups of these chemical compounds were identified that could potentially be placed in each segment of the frac fluid so as to more directly measure the flowback efficiency of each fluid segment. Armed with this flowback profile data together with the treatment pressure history of the frac treatment, it was believed that much could potentially be learned both about the dynamics of segmented fluid placement as well as segmented fluid flowback and cleanup. Given the established formation/fracture damage potential for conventional proppant transport fluids, those fluid segments not adequately recovered following the treatment could, in principle, detrimentally affect the flow capacity of the propped fracture. Chemical frac tracers were designed to be placed in chemically-differentiated and/or proppant-differentiated fluid segments of the fracturing fluid so as to assess the cleanup of the fracture as a function of segment fluid chemistry and/or fracture geometry. In so doing, it was believed that the sufficiency or insufficiency of addition rates for key frac fluid additives such as polymers, breakers and gel stabilizers could be assessed. It was also believed that the relative cleanup of individual frac treatment segments in a multiple stage completion procedure could be monitored. It was further hoped that inferences could be made from these data regarding lateral placement effectiveness of proppants and vertical communication between zones. Furthermore, the tracer analysis results could be used to assess the amount of each injected segment recovered and hence to calculate flowback efficiency. To fully investigate frac fluid compatibility of these chemical tracers, a series of rheology tests were designed and conducted with the Fann Model 50. Two generic frac fluids were selected to evaluate the effects of these chemical tracers on the viscosity of these frac fluids. These fluids are zirconate-crosslinked 35 lb/Mgal CMHPG (carboxymethyl hydroxypropyl guar) and borate-crosslinked 40 lb/Mgal guar gel. The first two tests were designed to establish a baseline for the viscosity of these two fluids without the addition of any chemical tracers. The viscosities of borate-crosslinked guar and zirconate-crosslinked CMHPG, the two generic fracturing fluids, at 250ºF and after 60 minutes at various shear rates, did not change with the addition of chemical frac tracers at concentrations of up to 100 ppm for zirconate-crosslinked CMHPG and more than 10 ppm for borate-crosslinked guar. The percent change in the pH of borate-crosslinked guar and zirconate-crosslinked CMHPG for the before and after rheology tests at 250ºF and 60 minutes with the addition of tracer is well within the percent change of fluid pH without the addition of tracer under similar testing conditions (Sullivan et al. 2004). Background Fluid flowback can be either of a fracture-tip or near-wellbore type. If flowback is of the near-wellbore type, it indicates extensive near-wellbore leakoff owing to a highly permeable zone around the wellbore. This causes much of the pad fluid segment to leakoff near the wellbore and, therefore, the pad fluid is first to be recovered. In a low permeability formation, pad flows to the fracture tip owing to low permeability and/or damaged permeability around the wellbore resulting in minimal leak-off near the wellbore. Once the well is subjected to flowback under this condition, what is injected first flows back last, if fluids are formulated properly. If some segments of gelled frac fluid are not broken effectively before the well is subjected to flowback, the early injected fluids could potentially finger through the late injected unbroken fluids and flowback first. In general, the flowback order of each segment depends on a number of factors, such as fluid type and polymer concentration, crosslinker concentration, breaker loading, pumping schedule, closure pressure, and flowback schedule, to name a few. Therefore, comprehensive diagnoses of flowback can only be accomplished with complete injection and flowback information. The detrimental effects of reduced fracture conductivity as a result of poor flowback are well documented in the literature. Most references have focused on the effects of using improper flowback procedures on well performance (Veatch and Crowell 1982; Hickey et al. 1981; Robinson et al. 1988; Barree and Kukherjee 1995). The associated effects are proppant movement into the wellbore, proppant crushing at or near the wellbore, and fracture plugging yielding reduced conductivity and productivity. Although fluid flowback is an important part of the fracture treatment, it has been overshadowed by proppant flowback concerns in recent years. The conventional method of quantifying fracture cleanup has been to report load water recovered during flowback. This value, however, is greatly influenced by the volume of formation water produced. It also, at best, provides information on the total recovery rather than the flowback of each frac fluid segment.

Required Understanding for the Development of Shale Reservoirs in the Middle East in Light of Developments in North America

“…If the reservoir permeability is high, then the fluid will invade the adjacent areas to the fracture face not deep in the fracture and fracture tip. In case of low permeability reservoirs, the fracturing fluids will penetrate the formation by increasing the fracture depths and so leakoff can take place through the fracture tip (Asadi et al 2008). Many factors can affect the flowback after fracturing job, such as pumping schedule, fluid type and the fracturing fluid chemistry (polymer loading, cross linkers and breakers).…”

Understanding Flowback as a Transient 2-Phase Displacement Process: An Extension of the Linear Dual-Porosity Model

“…Among existing flowback chemical analysis models (Asadi et al, 2008;Sullivan et al, 2004;Willberg et al, 1998;Woodroof et al, 2003), Gdanski et al (2007) was on of the first to incorporate a chemistry layer to a 2-D numerical simulator. This simulator was used to history-match the composition of flowback fluid.…”

“…This calls for a model that captures the transient 2-phase (gas/oil + water) flow in HF, and can be used for history matching rate and pressure data measured during flowback operations. Flowback chemical (tracer) analysis (Asadi et al, 2008;Sullivan et al, 2004;Willberg et al, 1998;Woodroof et al, 2003) could provide (1) an efficient means of differentiating formation water from flowback water (fracturing fluid + formation water) and (2) an optimal fracture clean-up or load recovery workflow.Developing an appropriate model for analysing rate/pressure measured during flowback operation requires a proper review of the static framework and flow physics of existing unconventional reservoir models. This paper extends the existing linear dual-porosity model (DPM) and develops a flowback analysis model (FAM) which accounts for transient multiphase flow in HF.…”

“…This model assumes that water-saturation drop with time causes a corresponding non-linear increase in hydrocarbon relative-permeability in HF. The application and drawbacks of these methods are discussed below.Among existing flowback chemical analysis models (Asadi et al, 2008;Sullivan et al, 2004;Willberg et al, 1998;Woodroof et al, 2003), Gdanski et al (2007) was on of the first to incorporate a chemistry layer to a 2-D numerical simulator. Fifteen tight oil, tight gas and shale gas wells completed in the Bluesky, Cardium, Evie, Muskwa and Otter-Park Formations were used for this study.…”

Observation of Gel Filter Cake Recovery by Dissolution in Flowback Fluids

“…Understanding and modeling the recovery of gel filtercakes, whether permanently crosslinked with metals or reversibly crosslinked with boron, continues to be a subject of interest (Asadi et al 2008;Hutchins et al 2011). Field studies have indicated a positive correlation between gel recovery and gas productivity (Pope et al 1996).…”