Chemical Tracer Flowback Data Help Understanding of Fluid Distribution
Authors: Carpenter Chris 
Published: September 2019

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194362, “Understanding Fracturing-Fluid Distribution of an Individual Fracturing Stage From Chemical Tracer Flowback Data,” by Wei Tian and Alex Darnley, SPE, ResMetrics; Teddy Mohle, SPE, and Kyle Johns, Contango Oil and Gas; and Chris Dempsey, ResMetrics, prepared for the 2019 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, 5–7 February. The paper has not been peer reviewed.
This paper presents a data set involving the pumping of multiple, unique chemical tracers into a single Wolfcamp B fracture stage. The goal of the tracer test is to improve understanding of the flowback characteristics of individually tagged fluid and sand segments by adding another layer of granularity to a typical tracer-flowback report. The added intrastage-level detail can provide insights into fracture behavior in shale-reservoir stimulation by looking at individual fluid-segment tracer•recoveries.
Introduction
Operators have relied upon high-intensity completion designs that include a combination of high proppant volumes, increased perforation-cluster density, and smaller-mesh-size proppants. These designs aim to create a complex fracture network and increase the contact area with shale rock. They have helped operators achieve higher initial productivity and larger estimated ultimate recovery while simultaneously enabling the drilling of horizontal wells at tighter well spacing. The traditional, bi-wing fracture model seems to be scrutinized increasingly for its lack of relevance when stimulating shale reservoirs. Operators have observed greater fracture complexity when using enhanced completion designs. These designs aim to increase fracture surface area and complexity, leading to a debate regarding the merits of stimulated reservoir volume (SRV) and propped-stimulated reservoir volume, also known as effective propped volume (EPV).
SRV, estimated usually from micro seismic mapping, is a rough estimate of the volume of rock that is hydraulically fractured, and is sometimes defined as the product of gross stimulated area and pay-zone thickness. EPV is a fraction of the total SRV that is supported by proppant and is capable of flowing during depletion. From a production perspective, the surface-area contact of the fractional propped SRV is more important than the gross SRV estimate.
In the past, chemical tracer data have offered stage-level insights into load recovery and hydrocarbon contribution, but the data set presented in the complete paper considers individual fluid-segment data within a single fracturing stage. A few of the questions prompting this study included:
Do certain fluid segments exhibit poor tracer recovery by being placed within the unpropped fraction of the SRV?
Does the order of injected fracturing fluid correspond with the order in which tracer is produced?
Can the residence-time calculation for each tracer be used to infer the degree of fracture complexity?
As operators elect to enhance fracture complexity by increasing perforation-cluster density, using lower-viscosity-fluid systems, and pumping smaller-mesh proppants, the modeling of fracture geometry has proved difficult. In addition, varying perforation-cluster efficiency and sand-duning effects can cause fluid and proppant to be distributed nonuniformly within the fracture network.