Flow Rate-Dependent Skin in Water Disposal Injection Well

Abstract

Reinjection is one of the most important methods to dispose fluid associated with oil and natural gas production. Disposed fluids include produced water, hydraulic fracture flow back fluids, and drilling mud fluids. Several formation damage mechanisms are associated with the injection including damage due to filter cake formed at the formation face, bacteria activity, fluid incompatibility, free gas content, and clay activation. Fractured injection is typically preferred over matrix injection because a hydraulic fracture will enhance the well injectivity and extend the well life. In a given formation, the fracture dimensions change with different injection flow rates due to the change in injection pressures. Also, for a given flow rate, the skin factor varies with time due to the fracture propagation. In this study, well test and injection history data of a class II disposal well in south Texas were used to develop an equation that correlates the skin factor to the injection flow rate and injection time. The results show that the skin factor decreases with time logarithmically as the fracture propagates. At higher injection flow rates, the skin factor achieved is lower due to the larger fracture dimensions that are developed at higher injection flow rates. The equations developed in this study can be applied for any water injector after calibrating the required coefficients using injection step rate test (SRT) data.

Cloud computing and web application-based remote real-time monitoring and data analysis: slurry injection case study, Onshore USA

“…A thorough feasibility study was carried out for Karnes injection project and injection parameters were optimized based on injection test data and predictions from fracture simulations. Injection failures, however, could still occur during injection because of data uncertainties and the complex nature of injection (Bautista and Dahi Taleghani 2016;Mohamed et al 2016). These potential injection risks may be related to unidentified pre-existing faults, overestimated barrier stress for fracture containment, plugging along the wellbore or in the fracture, inter-well fluid communication, well integrity issues (such as packer failure and poor cement job), and so on.…”

A Two-Phase Numerical Model of Well Test Analysis to Characterize Formation Damage in Near-Well Regions of Injection Wells

“…To improve oil recovery, line drive patterns have been widely employed in offshore oilfields, as shown in Figure 1. However, formation damage is quite common in near-well regions of injection wells in offshore oilfields due to interaction between injection water and clay minerals [1][2][3][4][5][6][7][8][9][10][11][12]. To characterize the formation damage and estimate reservoir properties, transient pressure data observed from the testing wells are usually interpreted by traditional pressure transient analysis models [13][14][15][16][17][18][19][20][21][22], which are simplified single-phase models divided into two or three regions according to the properties of formation and fluids.…”

The Effect of Rheology of Viscoelastic Polymer on Pressure Transient Response in Near-Wellbore Regions

“…In the design and adjustment of the polymer flooding process, basic information of an oilfield is the key to success. Pressure transient analysis is an important method to characterize reservoirs [6][7][8][9][10][11][12], which can provide valuable information including permeability, degree of near-wellbore damage (skin factor) [13][14][15][16][17][18][19][20], and wellbore storage constant.…”