1. INTRODUCTION

In-situ stress condition is one fundamental parameter in a wide range of applications in rock engineering, including the oil/gas industry. For example, it is critical to design a safe and economic gas storage pressure for underground gas storage. Minifrac tests are the most reliable in-situ testing protocol for measuring the in-situ stress condition at deep depths. A minifrac test injects a controlled fluid volume at high pressures to create and propagate a fracture in the test interval and then, shut-in the well or flowback the fluid to monitor pressure decay. The fracture closes when the pressure declines to a certain level. The bottomhole pressure (BHP) at which the fracture closes, called fracture closure pressure, is equivalent to the formation’s in-situ minimum stress (Smin). For a minifrac test, two types of testing protocols can be employed, namely injection/leakoff (ILF) and injection/flowback (IFB). During an ILF test, following injection, the well is shut-in and the fluid leaks off through the fracture surfaces, causing the pressure decay inside the fracture. During an IFB test, following injection, a certain volume of fluid is carefully withdrawn from the injection system (wellbore plus the fracture), which causes the pressure

decay inside the fracture and its closure. Dedicated diagnostic methods are needed to interpret the fracture closure pressure from the pressure decay data (Economides and Nolte 2002).

The minifrac tests can be conducted on both an openhole and a cased hole. An advantage of the openhole test is that all the three principal in-situ stresses can be estimated from the test data. For more background information on the minifrac tests, one may refer to a review paper by Hudson and Brown (1993). Yuan et al. (2013) summarized various quality control issues for a minifrac test. Ahmed et al. (2016) presented technical operation details of an openhole minifrac testing program in Kuwait’s unconsolidated sands formation. Barree et al. (2009) presented a summary of the transient pressure analysis of the fracture closure pressure for minifrac tests without flowback. For information about the in-situ stress field in rock formations, one may refer to a book by Zang and Stephansson (2010).

Because of their impermeable nature, minifrac tests in salt formations pose significant challenges on the ILF testing protocol. The fluid leakoff through the fracture into the formation is significantly slow, and thus, it may take a

ARMA 17-745 Field Experience and Numerical Investigations of Minifrac Tests with Flowback Bin Xu BitCan Geosciences & Engineering Inc., Calgary, AB, Canada Tan Zhao and Xueqiang Yin China Tiancheng Engineering Inc., Tianjin, China Yanguang Yuan BitCan Geosciences & Engineering Inc., Calgary, AB, Canada

Copyright 2017 ARMA, American Rock Mechanics Association This paper was prepared for presentation at the 51st US Rock Mechanics / Geomechanics Symposium held in San Francisco, California, USA, 25-28 June 2017. This paper was selected for presentation at the symposium by an ARMA Technical Program Committee based on a technical and critical review of the paper by a minimum of two technical reviewers. The material, as presented, does not necessarily reflect any position of ARMA, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of ARMA is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 200 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgement of where and by whom the paper was presented.

ABSTRACT: More than 50 openhole minifrac tests were completed in a salt formation at depths of 1,100 to 1,500 mTVD for an underground gas storage project. Injection/flowback was implemented in each test to achieve accuracy and efficiency. This function is very important given the impermeable nature of salt and the necessity to complete each test in as short a period of time as possible. Each flowback cycle yields a distinct and repeatable fracture closure signature, which makes interpretation of the fracture closure pressure easier. The objective of this paper is to share field experience and present numerical analysis of the flowback test’s pressure response. Some example openhole minifrac tests in the salt formation are used as examples to demonstrate the site operation procedures. Then, two numerical models are presented to simulate the fracture closure behaviour during a flowback test. Field evidence is given to demonstrate that the fracture closure pressures from the flowback tests are identical to those from tests without flowback. It is hoped that this paper will provide more insight about flowback tests by sharing our successful experience and knowledge, thus benefiting the general industry.

long time for the fracture to close on itself. This is detrimental to the test’s efficiency and easy field operation logistics. In many situations, waiting for the fracture to close takes so long that the test is incorrectly terminated before the true fracture closure. As a result, the in-situ minimum stress measured in these premature minifrac tests is larger than the real value.

Minifrac tests with the IFB testing protocol can be used to overcome the challenges posed by the slow-leak behaviour in a salt formation. During the IFB test, the injected fluid is withdrawn at a controlled rate/volume from the injection system after the injection phase. The fluid withdrawal can be conducted at a constant rate or a constant choke valve opening. In the latter, the flowback rate remains either constant or declines with time. The fracture was thus managed to close quickly because of the manually induced pressure decay. The flowback volume could be adjusted during a test according to real-time analysis results. Compared with the ILF testing protocol, advantages of the IFB test are: a) the BHP response developed in the flowback phase has a distinct and repeatable signature that could be used to relatively and easily infer the fracture closure pressure; and b) in low-permeability formations, flowback tests are fast and efficient. Fig. 1 illustrates an openhole minifrac test with flowback in the salt formation. The test had five injection/flowback cycles, lasting 1.5 hours in total. Each test cycle had a pressure decay close to the hydrostatic level, which was well below expected theoretical fracture closure pressures. Namely, the pressure decay is sufficiently long, guaranteeing the fracture closure.

Fig. 1. An example openhole minifrac test with flowback conducted in a salt formation at a depth of 1,230 mTVD. The red line is the surface pressure plus the hydrostatic well column, the black curve is BHP recorded at sandface, the blue line is the downhole pressure below the lower packer, and the green line is the injection/flowback rate. Negative rates denote the flowback. Although minifrac tests with flowback have been practiced in the field, few publications are available about theoretical studies and detailed analysis on the fracture closure behaviour during a flowback test. Plahn et al.

(1997) presented a finite difference scheme to simulate the flowback process during a minifrac test. The fracture geometry in the simulations was assumed to be either PKN or KGD-type. Raaen et al. (2001) presented a system stiffness approach to determine the fracture closure event during the flowback tests. They considered that the injection system contains two parts: the wellbore and the fracture. Before the fracture closure, both the wellbore and fracture were active in the system. After the fracture closure, the system only contained the wellbore. Thus, after the fracture closure, there should be an obvious system stiffness change that results in two different slopes in a compliance plot (BHP vs. flowback volume). As described next according to our field experience and numerical modelling, this system compliance change is strongly affected by injected fluid volume, flowback rate, and formation permeability. Thus, it is important to strike a balance between the injected volume and the flowback rate in order to obtain a better-defined fracture closure event on the pressure data. In this paper, we first describe site operation procedures of an openhole minifrac test with flowback in a salt formation. The minifrac tests in an underground gas storage project are used as examples. Then, numerical models are presented to simulate the fracture closure behaviour during a flowback test. In order to attest the model capability, these models are used to history match real field data. Sensitivity analysis runs are conducted to investigate the influence of flowback rate, formation permeability, and injection volume on the performance of a flowback test. Field data are also given to prove that the fracture closure pressure from injection/flowback tests are identical to those from the conventional injection/leakoff tests. Conclusions and discussions are given to the end of this paper.

2. FIELD OPERATION PROCEDURES From year 2013 to 2015, more than 50 openhole tests were completed on four vertical wells at depths of 1,100 to 1,500 mTVD in an underground gas storage project. The major objective of these minifrac tests was to measure the in-situ stress condition and provide a guideline for the design of a safe gas storage pressure. The tests were conducted in a salt formation and flowback testing protocols were used in all the tests. The field equipment included two major parts: a) a surface injection system; and b) a downhole straddle packer system. An illustration of the field equipment layout is given in Fig. 2.

A specially designed manifold system was used in these tests, as shown in Fig. 3. This manifold system served two purposes: 1) to regulate the injection rates supplied by the site cementing pump to suitable levels required for a well-controlled minifrac test (i.e., relatively stable low rates)

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