A Mechanistic Model for Formation Damage and Fracture Propagation During Water Injection

Abstract

The majority of injectors are likely to be fractured (intentionally or unintentionally) during their life cycles. Assessment of facture conductivity damage and associated surrounding formation damage is an essential step for maximizing and maintaining injector performance during produced water injection for water flooding. Fractured injectors experience less injectivity decline over time in comparison to matrix injectors. The current paper will present a mechanistic model for the plugged fracture behavior and discuss its applications to field cases. In addition, implications, recommendations and best practices for optimized produced water injection will be addressed within this context. The well undergoes two distinct processes that alternate over its life to create the sustained injectivity behavior associated with this scheme. Injectivity damage can occur particularly in pseudo-matrix conditions, where a stationary fracture progressively plugs (in addition to permeability impairment of the surrounding reservoir rock), resulting in pressure buildup and injectivity decline. As solids are deposited in the fracture, the "effective" exposed surface area is gradually reduced, at least partially, as a function of the injected amount of solids.Furthermore, fracture face damage (external filter cake build-up) and accumulated surrounding formation damage (internal filter cake build-up) progress as the volume of injected water increases. This plugging process continues until the injection pressure required for the designated injection rate reaches a critical value, which is greater than the pressure required to re-fracture the formation and/or to extend or propagate the plugged fracture. At such pressure a sudden fracture propagation or further breakdown of the formation is evidenced by a sudden increase in the Injectivity Index or similarly, a sudden drop in the Reciprocal Injectivity Index - RII - (unit injection pressure per unit constant injection rate).Thereafter, the required pumping pressure drops and/or the injection rate increases with the newly created surface area that has been caused by fracture propagation or initiation.The process then repeats itself. As the pressure rises it approaches and finally exceeds the fracture pressure required for further propagation, resulting in a saw-toothed shape pressure-time (or rate-time) behavior. The slopes of the bounding lines are controlled by the damaged formation and fracture characteristics, as well as the injected water quality.The slopes can be made to diverge, converge or remain almost parallel. The third option indicates a well optimized injection scheme. The final section of this paper will imply lessons learned, mitigation strategies, conclusions and recommendations based on analyses of field data from a number of produced water injectors. Pressure transient analysis and results from pressure fall-off test will be presented to verify the study results. Introduction Practices in the oil and gas industry have had to adapt with stricter environmental laws and regulations. Produced Water (PW) management is one of the main operating standards that have been affected by these changes. The safe, environmentally friendly and economical handling of PW is an essential ingredient in the success of any operator. Fortunately, PW liability can be coverted into an asset through injection during waterflood operations, provided the operator can successfully manage the main concerns. Produced Water Re-Injection (PWRI) can meet both waterflooding and pressure maintenance requirements. Concerns regarding PWRI fall under two categories. First, is the water going where it is supposed to (i.e., profile conformance)? Second, can the desired injection rate be met, both in the short and long term (i.e., injectivity maintenance)? By assuring these two key issues, a successful injection project can be executed. Tracking PW injector's performance is required for assurance.

Water Quality and Well Injectivity: Do Residual Oil-in-Water Emulsions Matter?

“…Because no droplets have been detected at the outlet in Experiment SB50, all this injected oil volume is actually retained in the first half of the porous medium and, thus, the global oil saturation is 60%. A similar result has been already found by Soo et al (1984b) andAbou Sayed et al (2005). As pointed out by these authors, this confirms that no droplet coalescence is taking place inside the porous medium, otherwise such high oil saturation would have induced a continuous oil flow, which has not been observed.…”

“…PWRI is widely perceived as a risk-management process (Abou-Sayed et al 2005). Injectivity decline is among the main risks associated with PWRI, especially with matrix injection, even in soft formations (high JR), but also with above-fracture-gradient injection.…”

“…Matrix injection results in a continuous well-injectivity decline even in soft formations (Detienne et al 2005;Abou-Sayed et al 2007). Actually, recent field evidence indicates that most water-injection wells are likely to be fractured (Abou-Sayed et al 2005;Abou-Sayed et al 2007; Van den Hoek et al 2008) and that regular well acidizing is required to maintain injectivity even with clean water (Van den Hoek et al 2008). Thus, injectivity in hard formations is increasingly viewed as being dictated by a dynamic coupling between fracture growth and plugging (Detienne et al 2005).…”

Prediction of casing critical buckling during shale gas hydraulic fracturing

“…In summary, many factors are attributing to casing failure during hydraulic fracturing, resulting in different casing failure modes are being studied and documented in the literature (Yin et al 2018b, Zhaowei et al, 2017Li et al, 2012;Abou-Sayed et al, 2005). Nonetheless, another aspect that is presently receiving attention is multiple casing deformation points on lateral section of the well during fracturing as established by Xi et al (2018) and Yan et al (2017).…”

Simulation of Formation Damage after Long-Term Water Flooding

“…This high pressure in the reservoir causes stress redistribution and higher stress near the wellbore which induces material damage and permeability change. Experimental results show that dramatic increase of permeability occurs after rock damage [4][5][6]. Different mechanical models of describing the rock damage and permeability change have been established.…”