Theoretical Model and Numerical Investigation of Near-Wellbore Effects in Hydraulic Fracturing

Abstract

Summary The high near-wellbore pressure drop, which has frequently been reported in fracture treatments, is indicative of ineffective communication between the wellbore and the fracture. Although numerous observations of such effects have been published, few attempts have been made to understand them. This article describes three possible mechanisms of near-wellbore effects [perforation phasing misalignment-induced rock pinching, perforation pressure drop, and fracture reorientation (deviation tortuosity)] and their implementation in a numerical fracture simulator. Typical signatures of all three effects in fracture treatment records are shown, and a method is proposed by which to distinguish them. Perforation phasing misalignment has been identified as a cause of near-wellbore restriction. Because the fracture does not always initiate at the perforation, the fluid must communicate with the fracture through a narrow channel (microannulus) around the casing. Here we describe this pinching effect and show that it is related to the contact stress between the cement and the formation. Perforation pressure drop and deviation tortuosity, which have previously been proposed by other authors, have also been modeled. They have been incorporated into the simulator, together with the phasing misalignment effect, to allow investigation of the differences in response between the different mechanisms. Results of simulating the effects of erosion of near-well effects on treating pressure are also shown. Comprehensive field cases studies exhibiting near-wellbore mechanics are presented. The relevant near-wellbore mechanism is first identified and the downhole pressure is then simulated, demonstrating the validity of the model. Introduction Over the past few years, high near-wellbore pressure drop has often been observed in fracture treatments, and attempts have been made to understand the effect of near-wellbore conditions on the placement of proppant1,2 and to develop new methods to prevent unplanned screenouts.3–5 Near-wellbore pressure drops have been attributed to phenomena such as wellbore communication (perforations), tortuosity (fracture turning and twisting), and multiple fractures. These geometries were identified as being detrimental to the success of a fracturing treatment because of the increase in net pressure and the increased likelihood of unplanned screenouts. Over the past few years, significant effort has been devoted to developing field methodologies to overcome the effects of near-wellbore pressure losses. The use of small, high-concentration proppant slugs has been recommended to induce screenouts of secondary fracture strands in cases where multiple near-well fractures are suspected. Injection of low concentration proppant slugs has also been suggested to remove near-wellbore effects due to phasing misalignment and insufficient perforations. The use of a viscous fluid has also been proposed to prevent premature screenouts by increasing the near-wellbore fracture width in the tortuous path for a single fracture,2 or by biasing the near-wellbore hydraulic conductivity for a multiple fracture system,6 thereby preventing premature screenouts. In this article we focus on the identification and evaluation of fracture treatments showing near-wellbore effects. A model is proposed here to take into account such effects. The theoretical model has the inherent advantage of measuring near-wellbore pressure losses in terms of the underlying physical variables contributing to these effects. Additionally, the model considers the evolution of these physical parameters, and hence changes in near-wellbore pressure losses, as the treatment progresses, thereby permitting a robust re-design of the main fracture treatment. Current Near-Wellbore Evaluation Tests It is generally accepted that pressure losses associated with near-wellbore effects are proportional to the injection rate raised to a suitable power, a, (?PNWB˜qa) where a depends on the dominant near-wellbore mechanism. This observation has led to recommending rate changes as a part of the calibration treatment,7 or even during proppant injection.4 Instantaneous bottomhole pressure drops corresponding to these rate changes are then used to determine the existence of near-wellbore effects. A particularly useful field methodology used to identify near-wellbore effects is the step-down test. This test calls for monitoring bottomhole pressure drops corresponding to a progressively decreasing injection rate. A plot of ?PNWB vs. ?q is then used as a diagnostic tool to characterize whether insufficient perforations or fracture re-orientation is the cause of near-wellbore pressure losses: concave-up behavior is indicative of perforation pressure drops (?PNWB, P˜q2) while concave-down behavior is characteristic of fracture re-orientation (?PNWB, P˜q0.5) A theoretical analysis for identification of multiple fractures using a step-down test was presented by Chapman et al.7 The step-down test pressure characteristics of multiple fracture dominated near-wellbore pressure losses were shown to be similar to those exhibited by fracture re-orientation. To date, no equivalent tests are known to diagnose near-wellbore effects due to phasing misalignment. Near-Wellbore Geometry Several researchers have investigated critical mechanisms related to fracture initiation from vertical and deviated wells. Behrmann and Elbel8 found that the perforation must be oriented within a small angle of the plane normal to the minimum far-field stress for a fracture to initiate at the perforation and extend. These limited experiments suggested that this angle is about 10°. Other experiments have shown that, when the perforations are misoriented and the well deviated, the fractures can be nonplanar or S shaped.9 It has also been observed that the increase in breakdown pressure can be related to near-wellbore pressure drop in horizontal wells. However, in field operations it has been very difficult to predict the near-wellbore pressure drop because of the uncertainty of the reorientation path geometry. More recently, the creation of multiple fractures during a treatment has been identified as a mechanism which could explain the near-wellbore pressure drop.4 This effect was not considered in the work described in this article.

Patterns in complex hydraulic fractures observed by true-triaxial experiments and implications for proppant placement and stimulated reservoir volumes

“…Smooth reorientation was most commonly observed as fractures transitioned from longitudinal with the wellbore in the near-well zone to be perpendicular to the minimum principal stress further from the well. This curvilinear geometry was less apparent in our experiments than in previous works that used larger wellbores and more homogeneous materials (Abass et al 1996;Hallam and Last 1991;Romero et al 1995;Weijers et al 1994). Our most prominent examples of smooth reorientation were observed in E01-00-true-triaxially confined high-strength cement with brine injection and G01-90-true-triaxially confined granite with oil injection.…”

“…Rock stresses are the dominant factor affecting fracture geometry with tensile hydraulic fractures preferentially orienting perpendicular to the minimum principal stress direction (Warpinski et al 1982a, b;Zoback et al 1977). The influence of the near-wellbore zone can add complexity to the fracture, where examples show that fractures tend to initiate with orientations parallel with the borehole axis even if the borehole is drilled parallel with the minimum principal stress (Hallam and Last 1991;Romero et al 1995). It is relevant to note that these studies observed an offset branching pattern along the wellbore when hydraulic fractures initiated at an angle other than perpendicular to the minimum principal stress (Weijers et al 1994), which is unlike the idealized curving pattern predicted by continuum theory (Abass et al 1996;Valkó and Economides 1995).…”

Simulation of non‐planar three‐dimensional hydraulic fracture propagation

“…If these perforations are not perpendicular to the minimum in‐situ stress, the fractures will reorient themselves toward the direction of least resistance. This can lead to highly non‐planar fracture surfaces near the wellbore, which may cause failure of hydraulic fracturing treatments . This problem is investigated in Section 7.3 with the proposed generalized FEM (GFEM).…”

“…If these perforations are not perpendicular to the minimum in-situ stress, the fractures will reorient themselves toward the direction of least resistance. This can lead to highly non-planar fracture surfaces near the wellbore, which may cause failure of hydraulic fracturing treatments [2]. This problem is investigated in Section 7.3 with the proposed generalized FEM (GFEM).Adachi et al [3] presented an exhaustive summary of early 2D models and the so-called Pseudo-3D (P3D) models currently used for hydraulic fracturing simulations in the industry.…”

Advances in Laboratory‐Scale Hydraulic Fracturing Experiments

“…ey can be classified into the following four categories: (1) two-dimensional (2D) models (e.g., PKN model [11], KGD model [12], and penny-shaped model [13]), (2) pseudo three-dimensional (P3D) models (e.g., cell-based model [14] and lumped parameter model [15]), and (3) three-dimensional (3D) planar models [16]. However, these theoretical models are not widely used in applications as they are incapable of reproducing the 3D nature of hydraulic fractures and do not account for the near-wellbore effects and the interaction between natural and hydraulic fractures [17,18].…”