In-Depth Diversion
In-depth diversion refers to the strategic placement of chemical agents—such as gels or polymers—deep within the reservoir to divert injected fluids away from high-permeability channels or thief zones and improve sweep efficiency. This approach is particularly valuable in heterogeneous reservoirs where near-wellbore treatments are insufficient to manage water channeling or fracture-dominated flow. The technical publications featured here examine the efficacy, placement behavior, and field performance of in-depth diversion technologies, with a focus on colloidal dispersion gels (CDGs) and deep gelation methods.
Key studies by Seright and Wang critically assess the performance claims surrounding CDGs. Using a thorough literature review and laboratory validation, the research challenges the notion that CDGs can propagate deeply into porous rock while maintaining superior resistance factors compared to traditional HPAM polymers. Their findings reveal that most CDG systems gel too quickly to penetrate far into the formation and may lead to face plugging or fracture extension—undermining treatment objectives.
Other contributions explore how polymer flooding compares with in-depth gelation under various geological conditions. The research underscores that while polymer flooding is often more cost-effective and easier to implement in moderately heterogeneous systems, in-depth gelation may be justified in severely channeled or fractured formations—provided the treatment is carefully designed based on reservoir diagnostics.
This section also includes a critical exchange of viewpoints on field practices in China’s Daqing field, offering valuable insights into the complexity of field-scale performance validation and the need for robust interpretation beyond wellhead pressure data like Hall plots.
Explore the articles below to better understand the mechanisms, risks, and decision-making criteria behind in-depth diversion technologies—ensuring smarter chemical EOR and conformance designs in complex reservoir settings.
Table of Contents
In this published discussion and reply, Seright critiques the conclusions drawn in Chang et al. (2006) regarding the claimed superiority of colloidal dispersion gels (CDGs) over conventional polymer flooding. Seright challenges the assertion that CDGs penetrate deeply and offer higher resistance factors than HPAM polymers, citing contrary evidence from three university labs. The reply by Chang and co-authors defends their field-scale CDG/polymer results from the Daqing oil field, emphasizing that CDGs can complement polymer flooding by delaying water cut increases and extending project life. Both sides agree on the need for more research to understand the mechanisms of CDG behavior.
This paper examines literature that claims, suggests, or implies that floods with “colloidal dispersion gels” (CDGs) are superior to polymer floods for oil recovery. The motivation for this report is simple. If CDGs can propagate deep into the porous rock of a reservoir, and at the same time, provide resistance factors or residual resistance factors that are greater than those for the same polymer formulation without the crosslinker, then CDGs should be used in place of polymer solutions for most/all polymer, surfactant, and ASP floods. In contrast, if the claims are not valid, (1) money spent on crosslinker in the CDG formulations was wasted, (2) the mobility reduction/mobility control for CDG field projects was under-designed, and (3) reservoir performance could have been damaged by excessive loss of polymer, face-plugging by gels, and/or excessive fracture extension.
From this review, the clear answer is that there is no credible evidence that colloidal dispersion gels can propagate deep into the porous rock of a reservoir, and at the same time, provide resistance factors or residual resistance factors that are greater than those for the same polymer formulation without the crosslinker.
CDGs have been sold using a number of misleading and invalid arguments. Very commonly, Hall plots are claimed to demonstrate that CDGs provide higher resistance factors and/or residual resistance factors than normal polymer solutions. However, because Hall plots only monitor injection pressures at the wellbore, they reflect the composite of face plugging/formation damage, in-situ mobility changes, and fracture extension. Hall plots cannot distinguish between these effects—so they cannot quantify in situ resistance factors or residual resistance factors.
Laboratory studies—where CDG gels were forced through short cores during 2–3 h—have incorrectly been cited as proof that CDGs will propagate deep (hundreds of feet) into the porous rock of a reservoir over the course of months. In contrast, most legitimate laboratory studies reveal that the gelation time for CDGs is a day or less and that CDGs will not propagate through porous rock after gelation. A few cases were noted where highly depleted Al and/or HPAM fluids passed through cores after one week of aging. However, unless these particular formulations/experiments were sparse statistical outliers, they still do not support the hypothesis that CDGs will work in field projects as claimed.
In recent years, operators have increasingly turned to polymer flooding and in-depth gel placement as cost-effective means to improve sweep efficiency in waterfloods. However, questions persist about which method is more effective under various reservoir conditions. This paper presents a framework for comparing the two technologies in terms of cost, oil recovery, injectivity, and operational complexity. Laboratory data and field case studies are examined to show under what circumstances each technique has yielded superior results. The work emphasizes that a clear understanding of reservoir heterogeneity and waterflood behavior is essential for making the right choice. A key conclusion is that polymer flooding is often preferable for improving volumetric sweep when reservoir heterogeneity is not extreme, whereas in-depth gelation may be more suitable for severe channeling problems in fractured or high-permeability streaked reservoirs.
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