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Summary As life-span extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oil fields by improving the sweep efficiency of improved-oil-recovery (IOR)/enhanced-oil-recovery (EOR) floods. This paper presents a comprehensive review of the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and US Department of Energy reports. Seven parameters related to the oil-production response were evaluated according to the reservoir lithology, formation type, and recovery process, using univariate analysis and stacked histograms. The interquartile-range (IQR) method was used to detect the underperforming and overperforming gel projects. Scatterplots were used to identify the effects of the injected-gel volume and the treatment timing on the treatment response. Pretreatment water cut, recovery factor, and flood life were used as indicators for the treatment timing. Results indicated that gel treatments have very wide ranges of response for injection and production wells and for oil and water rates and profiles. When successfully applied, they, on average, respond after 3.5 months, increase the oil-production rate by 32%, and additionally recover 116,000 STBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate (CB) than in sandstone (SS) reservoirs and in naturally fractured (NF) formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected-gel volume for all formation types, not just for the matrix-rock (MR) reservoirs. Moreover, gel treatments applied in NF formations have lower productivities in SS than in CB reservoirs using normalized performance parameters. Declining trends were identified for all parameters of the oil-production response with the treatment-timing indicators. The sooner the gel treatment is applied, the faster the response, and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in MR formations because their response times might extend to several months. Gel treatments will perform more efficiently if they are conducted at water cuts of less than 70%, flood lives of fewer than 20 years, or recovery factors of less than 35%. For different application environments, the present review provides reservoir engineers with updated ideas regarding the low, typical, and high performances of gel treatments when successfully applied, as well as how other treatment aspects affect performance.

Summary Fractures and oil-wet conditions significantly limit oil recovery in carbonate reservoirs. Gel treatment has been applied in injector wells to modify the prevailing reservoir streamlines and significantly reduce fracture permeability, whereas low-salinity waterflooding has been applied experimentally to modify rock wettability toward water-wet for improved oil recovery. However, both processes have limitations that cannot be resolved using a single method. The objective of this study was to test whether low-salinity water could enable gel particles to move deeply into fractures to efficiently increase oil recovery and control water production. A semitransparent fracture model of carbonate cores and acrylic plates was built to study the effect of low-salinity waterflooding, fracture width, gel-injection volume, and fracture uniformity on oil recovery and to redirect the flow path to unswept zones. Preformed partial gel (PPG) and brine movements were visible through the model's transparent acrylic plate. Seawater was used for brine flooding and to prepare swollen particles; the seawater was diluted 100 times to create low-salinity water. A light crude oil was used, with 10-cp viscosity. Low-salinity water was injected after gel placement to test the gel-plugging efficiency. The results showed that the low-salinity water could improve gel propagation into the fracture and increase oil recovery because the gel strength (apparent viscosity) decreased as the brine concentration decreased. The gel-injection volume had a significant effect on the oil-recovery factor when seawater flooding followed the gel-injection process, although there was less of an effect when the gel was followed by low-salinity waterflooding. Moreover, the effect of low-salinity waterflooding on gel propagation decreased as the fracture width decreased. In addition, the resulting fracture uniformity illustrates a viable effect of the in-depth water-diversion treatment.

Summary It is of major importance to analyze polymer-flooding data because they can be used to obtain screening criteria and identify where and how polymer can be best used to enhance oil recovery. However, recently published screening criteria regarding polymer flooding were based on data collected from the biannual enhanced-oil-recovery (EOR) surveys published by the Oil & Gas Journal. These data recorded valuable information for finished and ongoing polymer flooding worldwide, but they are constrained in two ways. First, they do not include some important information, such as the formation-water salinity, divalent-cation concentration, and polymer type and concentration. Second, the field data do not reflect recent polymer-technology developments that are still in the laboratory-evaluation and pilot-testing stages. To overcome these limitations, a comprehensive data set that provides the overall picture of polymer-flooding research and application is presented in this paper. In total, 865 polymer-flooding projects were considered to construct the data set, including 481 field projects from the Oil & Gas Journal (1974–2012), 329 laboratory experiments (1964–2013), and 70 pilot test projects (1966–2016) recorded in the literature. The laboratory data include porosity, permeability, oil viscosity, polymer molecular weight (MW), polymer viscosity, polymer concentration, polymer-slug size, water salinity, and divalent-cation concentration. All the data reported in this paper showed the experimental conditions that researchers used, which is consistent with the objective of our work. Our purpose is to summarize the data and tell the conditions in which polymer had been tested rather than presenting the screening criteria for polymer-flooding applications. For pilot and field tests, we only select those papers in which a project reaches or exceeds the goal of the project design. Graphical and statistical methods are used to analyze and describe the data set. The distribution of major parameters important to polymer-flooding design is presented with histograms, and the range of all parameters and their statistical values are presented with box plots. The existing data collected in this work have been statistically analyzed, resulting in some generic trends that could aid future readers in the design of a successful polymer-flooding project, such as data pertaining to the formation-water salinity, polymer MW, concentration, and polymer viscosity.

SummaryEnhanced-oil-recovery (EOR) screening is considered the first step in evaluating potential EOR techniques for candidate reservoirs. Therefore, as new technologies are developed, it is important to update the screening criteria. Many of the screening criteria regarding polymer flooding that have been described in the literature were based on data collected from EOR surveys of the Oil and Gas Journal. However, the data quality has not been addressed in previous research. The data set originally contained 481 polymer-flooding projects from around the world, and it contained some problems, including outliers and duplicate, inconsistent, and missing data. To ensure the quality of the data set before running analyses, boxplots and crossplots were used to detect and identify data problems. After detecting outliers and deleting duplicate and severely inconsistent data records, only 250 projects remained. Both graphical and statistical methods were used to analyze and describe the results of the data set. Two major sets of information were given after data cleaning: The first was that the majority distribution of each parameter was shown by use of a histogram distribution, and the second was that the range of each parameter and some of its statistical values were presented by use of a boxplot. Finally, the screening criteria are presented on the basis of these statistics and the defined data parameters. The developed criteria were compared with previously published criteria, and their differences were explained. The developed criteria show that a polymer-flooding project can be successfully applied in a reservoir with a temperature of less than 210°F, an oil viscosity up to 5,000 cp, and gravity lower to 12°API.