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.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
27 October 2006
- Meeting paper published:
5 December 2006
- Revised manuscript received:
22 August 2007
- Manuscript approved:
30 August 2007
- Version of record:
20 May 2008
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