Comprehensive evaluation of a novel EOR method-coupling low salinity water flooding and preformed particle gel to enhance oil recovery in fractured reservoirs

Excess water production in oil fields is becoming a challenging economic and environmental problem as more reservoirs are maturing. Water channeling, one of the primary reservoir conformance problems, is caused by reservoir heterogeneities that lead to the development of high-permeability streaks. The recovery of oil from carbonate reservoirs is usually low due to their extreme heterogeneity caused by natural fractures and the nature of oil-wet matrix. Also, oil recovery from fractured sandstone reservoirs is often low due to areal heterogeneity. Gel treatments have proven to be a successful and inexpensive fluid diversion method when used to plug the thief zones and thereby improve sweep efficiency in reservoirs. However, particle gel treatment can only be used to plug fractures or high permeable channels to improve sweep efficiency and has little effect on displacement efficiency. Oil recovery is the product of displacement efficiency (ED) and sweep efficiency (ES). Particle gels can plug fractures and improve sweep efficiency, but they have little effect on displacement efficiency. Low salinity water flooding (LSWF) can only increase displacement efficiency but has little or no effect on sweep efficiency. The main objective of this research is to provide a comprehensive understanding of the combined LSWF-PPG technology and to show how the coupling method can improve oil recovery. We developed a cost-effective, novel, enhanced oil recovery (EOR) technology for fractured reservoirs by coupling the two technologies into one process. The coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency --Abstract, page iv

Asphaltene Precipitation Investigation Using a Screening Techniques for Crude Oil Sample from the Nahr-Umr Formation/Halfaya Oil Field

Many oil and gas processes, including oil recovery, oil transportation, and petroleum processing, are negatively impacted by the precipitation and deposition of asphaltene. Screening methods for determining the stability of asphaltenes in crude oil have been developed due to the high cost of remediating asphaltene deposition in crude oil production and processing. The colloidal instability index, the Asphaltene-resin ratio, the De Boer plot, and the modified colloidal instability index were used to predict the stability of asphaltene in crude oil in this study. The screening approaches were investigated in detail, as done for the experimental results obtained from them. The factors regulating the asphaltene precipitation are different from one well to another, from the high-pressure-temperature reservoir to surface conditions. All these factors must be investigated on a case-by-case basis. Because the Halfaya oil field is still developing its petroleum sector, modelling, and forecasting the phase behavior and asphaltene precipitation is crucial. This work used crude oil bottom hole samples with an API of equal to 27 from a well in the Halfaya oil field/Nahr-Umr formation to create a thermodynamic model using Multiflash software. The data included the compositional analysis, the PVT data, and reservoir conditions. The thermodynamic model of asphaltene phase behavior was proposed using the Cubic-Plus association equation of state. All the screening techniques' results revealed the presence of an asphaltene precipitation issue (asphaltene unstable), which was confirmed by a thermodynamic fluid model. The aim of this paper is to predict the problem of asphaltene precipitation so that future proactive remedial methods can be developed to decrease the time and expense associated with it

Combined Ionically Modified Seawater and Microgels to Improve Oil Recovery in Fractured Carbonate Reservoirs

Modified waterflooding is a process in which the ionic composition of injected water is altered to improve oil recovery. Recently, extensive studies on crude oil, brine, and rock systems reported that the composition of injected water can change rock wettability during waterflooding. Carbonate reservoirs are mixed or oil wet reservoirs and most of these reservoirs are fractured, resulting in low oil recovery. In the last decade, many researchers conducted laboratory experiments to evaluate gel treatment in fractured models. The objective of this study is to examine the effects of sulfate ion concentration and low salinity water (diluted seawater) on improving oil recovery in fractured and nonfractured reservoirs when combined with microgel treatment. Four key parameters were examined: increased sulfate ion concentration, a degree of seawater dilution, fracture width, and matrix permeability. Three models were designed and tested in this work: nonfracture, fully-open fracture, and partially-open fracture model. Three different sulfate ion concentrations (typical seawater and that which was doubled and then tripled in sulfate ion concentration) and low salinity water that had been diluted 10 and 100 times were applied as waterflooding processes in two fracture widths (0.5 mm and 1 mm) with two different matrix permeabilities (20 md and 2.44 md). Microgel (425 µm in size) was swollen in typical seawater and injected in the fractured model to block the fractures and divert the brine into the matrix. The results show that increased sulfate ion concentration and diluted seawater can improve oil recovery by changing core wettability towards water-wet conditions. We also found that diluted seawater can improve both displacement and sweep efficiency while increased sulfate ion concentration only improves displacement efficiency when applied after gel treatment in both fully open fractures and partially open fractures. Therefore, diluted seawater can improve plugging efficiency but sulfate ions cannot. Increased sulfate ion concentration followed by diluted sea water with microgel-filled fractures might be a viable technique to improve oil recovery in fractured carbonate reservoir. The sulfate ion concentration effects decrease as fracture width increases and matrix permeability decreases. Also, the diluted seawater effects decrease as matrix permeability decreases. Combining microgel with sulfate ion concentration results in higher oil recovery than combining microgel with low salinity water in fully open fracture. However, combining microgel with low salinity water showed highest oil recovery in partially open fracture

Field Performances, Effective Times, and Economic Assessments of Polymer Gel Treatments in Controlling Excessive Water Production from Mature Oil Fields

Polymer bulk gels have been widely applied to mitigate excessive water production from mature oil fields by correcting the reservoir permeability heterogeneity. This paper reviews water responses, effective times, and economic assessments of injection-well gel treatments based on 61 field projects. Eight parameters were evaluated per the reservoir type using the descriptive analysis, stacked histograms, and scatterplots. Results show that water production generally continues to increase after the treatment for undeveloped conformance problems. Contrarily, it typically decreases after the reactive gel treatments target developed conformance issues. For the developed problems, gel treatments do not always mitigate the water production where the water cut may stabilize or increase by 17% in 22% of instances. In addition, they often do reduce water production but not dramatically to really low levels where the water cut stays above 70% and reduces by only 10% in most cases. Gel treatments are economically appraised based only on the oil production response, and both water responses (injection and production) are not considered in the evaluation. They have a typical payout time of 9.2 months, cost of incremental oil barrel of 2 $/barrel, and effective time of 1.9 years. In addition, they have better water responses and economics in carbonates than in sandstones and in unconsolidated and naturally fractured reservoirs than in matrix-rock formations. The current review strongly warns reservoir engineers that gel treatments are not superior in alleviating the water production and candidates should be nominated based on this fact to achieve favorable economics and avoid treatment failures

Experimental Study of Combining Low Salinity Water Flooding and Preformed Particle Gel to Enhance Oil Recovery for Fractured Carbonate Reservoirs

Oil recovery from carbonate reservoirs is usually low due to their extreme heterogeneity caused by natural fractures and the nature of the oil-wet matrix. Low salinity water flooding (LSWF) and preformed particle gels (PPG) control conformance are two novel technologies that have recently drawn great interest from the oil industry. Theoretically, LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency; PPG can plug fractures, they can improve sweep efficiency, but they have little effect on displacement efficiency. We developed a cost-effective, novel, enhanced oil recovery (EOR) technology for carbonate reservoirs by coupling the two technologies into one process. The objective of this paper is to provide a comprehensive understanding of the combined technology and to demonstrate how the coupling method can improve oil recovery. The oil-wet carbonate cores provided a higher improved oil recovery than water-wet carbonate cores during LSWF. The decrease in fracture width resulted in a higher oil recovery factor. Compared to traditional bulk gel treatments, PPG forms stronger plugging but will not form an impermeable cake in the fracture surface; therefore, PPG allows low salinity water to penetrate into the matrix to modify its wettability, thereby producing more oil from the matrix. Results also show that oil recovery increased by 10% during LSWF after the second water flooding. Additionally, when PPGs were injected, another 4% of oil recovery was gained. As a result, the combined LSWF and PPG increased oil recovery by 18%. A full-factorial experimental design was performed to investigate the influence of the PPG-placed injection pressure (which refers to the maximum pressure used to inject PPG for each experiment), water salinity, and fracture width. Experimental results tell that PPG-placed injection pressure is the factor that strongly influences both oil recovery factor and residual resistance factor; fracture width is the least influential factor among the three. Experimental results prove that the coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency

Preformed Partial Gel Injection Chased by Low-Salinity Waterflooding in Fractured Carbonate Cores

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\u27s 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

Coupling Low Salinity Water Flooding and Preformed Particle Gel to Enhance Oil Recovery for Fractured Carbonate Reservoirs

The recovery of oil from carbonate reservoirs is usually low due to their extreme heterogeneity caused by natural fractures and the nature of the oil-wet matrix. Low salinity water flooding (LSWF) and preformed particle gels (PPGs) control conformance are two novel technologies that have recently drawn great interest by the oil industry. We developed a cost-effective, novel, enhanced oil recovery (EOR) technology for carbonate reservoirs by coupling the two technologies into one process. The objective of this paper is to provide a comprehensive understanding of the combined technology and to test through laboratory experiments the extent to which the coupling method can improve oil recovery. The laboratory experiments showed that the optimum water salinity for the application of the coupled method was 0.1 wt. % NaCl under experimental conditions. The water residual resistance factor (Frrw) increased as the water salinity and the fracture width decreased. The oil-wet carbonate cores provided a higher improved oil recovery than a water-wet carbonate cores during LSWF. The decrease in fracture width resulted in a higher oil recovery factor. Compared to traditional bulk gel treatments, PPG forms stronger plugging but will not form an impermeable cake in the fracture surface; therefore, PPG allows low salinity water to penetrate into the matrix to modify its wettability, thus producing more oil from the matrix. Results also show that oil recovery increased by 10 % during LSWF after the second waterflooding. Additionally, when PPG was injected, another 8 % of oil recovery was gained. As a result, combined the LSWF and PPG increased oil recovery by 18%. LSWF can increase only displacement efficiency but has little or no effect on sweep efficiency, while particle gels can plug fractures or in high-permeable channels to improve sweep efficiency but have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improve both the displacement and the sweep efficiency

A Review of Responses of Bulk Gel Treatments in Injection Wells -- Part II: Water Responses and Economic Assessments

Polymer bulk gels have been widely applied to mitigate excessive water production in mature oil fields by correcting reservoir permeability heterogeneity. This paper presents a comprehensive review of the water responses and the economic assessments of injection-well gel treatments. The survey includes 61 field projects implemented between 1985 and 2014 and compiled from SPE papers and U.S. DOE reports. Ten parameters were evaluated according to the reservoir lithology, formation type, and recovery process using the univariate analysis, stacked histograms, and scatterplots. Results indicated that gel treatments have very wide ranges of water injection/production responses and economic indicators. We identified that gel treatments do reduce the water production but not dramatically to really low levels. The water production continues to increase after the proactive treatments applied in undeveloped conformance problems at low water cuts ( \u3c 50%). Contrarily, the water production decreases after the reactive treatments conducted in developed conformance issues at high water cuts ( \u3e 50%). When successfully applied, gel treatments averagely reduce the water injection rate by 34% and the water cut by 10%; however, the water cut may also increase by 17%. For developed problems, the water cut may stabilize or increase after the remediation mainly in matrix-rock sandstone reservoirs, especially when small gel volumes are injected ( \u3c 1000 barrels) into this formation type. Economically, gel treatments are appraised solely based on the oil production response and both water responses are not considered in the evaluation. Typically, gel treatments have cost of incremental oil barrel of 2$/barrel and payout time of 9.2 months and function for 1.9 years. They have better water responses and economics in carbonates than in sandstones and in unconsolidated and naturally-fractured than in matrix-rock formations; however, they have reverse tends with respect to the gel effective time. The gel effective time significantly decreases with the channeling strength, the aperture of flow channels, and the temperature of injected drive-fluids. Generally, the water production response and economic parameters improve as the injected gel volume increases and the treatment timing advances in the flooding life. For different application environments, the present review provides reservoir engineers with updated ideas about what are the low, typical, and high performances of gel treatments when applied successfully and how other treatment aspects affect the performances

Combining Preformed Particle Gel and Low Salinity Waterflooding to Improve Conformance Control in Fractured Reservoirs

The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently drawn great interest from the oil industry. LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency whereas PPG can plug fractures and improve sweep efficiency, but they have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency. The main objective of this study was to determine whether the combining technologies can improve conformance control in fractured sandstone reservoirs. Before the study was conducted, the effects of low salinity waterflooding, number of fractures, and PPG strength were studied. The PPG was injected into the fracture at a flow rate 2.0 ml/min. Brine was injected at a different flow rate after PPG placement to test the effect of flow rate on the PPG\u27s plugging efficiency. Laboratory experiments showed that the oil recovery factor and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. However, the PPG extruded pressure decreased when the PPG swelled in a low-brine concentration. At a high-flow rate, there was no significant effect on the Frrw. Combining two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control

Mineral Dissolution and Fine Migration Effect on Oil Recovery Factor by Low-Salinity Water Flooding in Low-Permeability Sandstone Reservoir

The latest oil price decline simply increases the demand for enhanced oil recovery (EOR) and pushes research developers to keep improvements in oil recovery. The goal is always to recover as much oil as possible at the lowest possible cost. Low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods. The objective of this study was to test the ability of low salinity waterflooding to improve oil recovery from low permeability sandstone reservoirs. Four types of tests were conducted: imbibition, core flooding, zeta potential and scanning electron microscopy (SEM) tests. Two key factors were studied: salinity of the injected water and aging time. Their influence on the amount of oil recovery, stabilized injection pressure, pH, and permeability reduction was determined. The results showed that injected low brine concentration resulted in improving oil recovery. The oil recovery factor results during the second water flooding cycle (after aging for 24 h) showed more oil recovered during low water salinity injections. The zeta potential results showed that decreasing the salinity of injected water resulted in a decrease of the zeta potential value for both injection cycles, before and after aging for 24 h. Results also imply Low-salinity water flooding redistributes the flowing paths by releasing sand particles and some fine minerals causing the flow path to narrow. Thus, low salinity water flooding can create a new streamline (fluid flow diversion) and improve both displacement and sweep efficiency