Foams as Mobility Control Agents for Oil Recovery by Gas Displacement

Llave, F.M.; Chung, F.T.H.; Louvier, R.W.; Hudgins, D.A.

doi:10.2118/20245-ms

Cited by 43 publications

(12 citation statements)

References 26 publications

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“…Results show that foam was preferentially generated in the more permeable plug and could divert CO 2 towards the less permeable plug. Llave et al (1990) showed similar results with parallel plugs with permeability ratio of 4.6. Field trials have also been conducted with some success.…”

Section: Introductionsupporting

confidence: 69%

Retention of CO2-Foaming Agent in CO2-Foam Flooding of Heterogeneous Carbonate Reservoirs

2011

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The efficiency of carbon dioxide (CO 2 )-flooding in highly heterogeneous reservoirs may be low due to poor macroscopic sweep. One of the possible ways to increase macroscopic sweep efficiency is by reducing the CO 2 mobility by foam. Retention of the foaming agent during CO 2 -foam flooding is an important aspect affecting both technical and economical potential of the process. This paper presents both experimental and numerical simulation studies performed to investigate the retention of CO 2 -foaming agents in heterogeneous carbonate reservoirs. These reservoir types consist of high permeable "thief zones" -fractures or high permeable layers and the rest of the reservoir -matrix or low permeable layers. The retention of CO 2 -foaming agent was studied in flow-through laboratory experiments with CO 2 -foaming agents; branched ethoxylated sulphonates with different ethoxylation degree in outcrop Liege chalk rock at 55 o C. The retention of the foaming agents was determined by breakthrough curves based on chromatographic separation between the foaming agent and a tracer. The flow-through retention experiments were reproduced in a numerical simulator. The results indicate that the retention (the amount of foaming agent lost per rock weight) depends on the type of foaming agent and oil saturation. It is concluded based on simulation results that the amount of the foaming agents retained in heterogeneous reservoirs would strongly depend on its transfer mechanism from high into low permeable zones. The diffusion process is slow and therefore the foaming agent might penetrate only into a certain fraction of the matrix blocks or low permeability layers during the project life time. The retention of the foaming agent in these heterogeneous carbonate reservoirs may therefore be much lower than estimated based on viscous floods. A numerical model describing diffusion and retention by adsorption was established. A good match between experimental and modeling results was obtained without individually tuning the numerical model for each specific experiment. Additional simulation results showed that on the field scale the amount of foaming agent retained in heterogeneous reservoirs will depend on the number of high permeable zones and the size of the matrix blocks.

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Section: Introductionsupporting

confidence: 69%

Retention of CO2-Foaming Agent in CO2-Foam Flooding of Heterogeneous Carbonate Reservoirs

2011

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“…Diversion of gas into lower-permeability layers using foams has previously been reported [see, for example, Casteel and Djabbarah (1988), Llave et al (1990), Zerhboub et al (1994), and Nguyen et al (2003)]. This may be important for fractured systems, where a very large permeability contrast exists and crossflow between the zones occurs (Bertin et al 1999).…”

Section: Introductionmentioning

confidence: 96%

Experimental Study of Foam Flow in Fractured Oil-Wet Limestone for Enhanced Oil Recovery

Haugen

Fernø

Graue

et al. 2012

SPE Reservoir Evaluation &Amp; Engineering

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Our objective was to study foam flow in fractured, oil-wet carbonate rocks and determine if foam may be a viable enhanced-oilrecovery (EOR) agent in such reservoirs. We present experimental results in fractured carbonate rock and show effects of wettability on oil recovery when using foam. Oil recovery by water, surfactant, or gas injection exhibited low recovery, less than 10% of original oil in place (OOIP). Oil recovery during injection of pregenerated foam was improved significantly, with up to 78% of OOIP produced. Foam reduced the gas mobility in the fractured rock, increased differential pressure, and diverted flow into the oil-saturated matrix. However, a significant amount of foam injection was required for the additional oil recovery. Generation of foam in-situ was weak in the smooth-walled fractures, and no fluid diversion from the fractures with additional oil recovery was observed. On the basis of the experimental results, mechanisms for foam collapse in the fracture are discussed and possible steps to improve recovery are outlined.

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“…Permeability contrasts have significant effects during EOR projects in which the injected EOR agent tends to flow within the fracture network rather than sweep the oil-saturated matrix blocks (Manrique et al 2007). In addition, oil is retained in the rock matrix by capillary forces in oil-wet formations (Hirasaki and Zhang 2004), but can be produced by either reducing the interfacial tension (IFT) or changing the matrix wettability using additives in the water including surfactants (Seethepalli et al 2004) or sulfate (Austad and Standnes 2003).…”

Section: Introductionmentioning

confidence: 99%

Experimental Study of Foam Generation, Sweep Efficiency, and Flow in a Fracture Network

et al. 2016

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Foam generation for gas mobility reduction in porous media is a well-known method and frequently used in field applications. Application of foam in fractured reservoirs has hitherto not been widely implemented, mainly because foam generation and transport in fractured systems are not clearly understood. In this laboratory work, we experimentally evaluate foam generation in a network of fractures within fractured carbonate slabs. Foam is consistently generated by snap-off in the rough-walled, calcite fracture network during surfactant-alternating-gas (SAG) injection and coinjection of gas and surfactant solution over a range of gas fractional flows. Boundary conditions are systematically changed including gas fractional flow, total flow rate, and liquid rates. Local sweep efficiency is evaluated through visualization of the propagation front and compared for pure gas injection, SAG injection, and coinjection. Foam as a mobility-control agent resulted in significantly improved areal sweep and delayed gas breakthrough. Gas-mobility reduction factors varied from approximately 200 to more than 1,000, consistent with observations of improved areal sweep. A shear-thinning foam flow behavior was observed in the fracture networks over a range of gas fractional flows.

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Foams as Mobility Control Agents for Oil Recovery by Gas Displacement

Cited by 43 publications

References 26 publications

Retention of CO2-Foaming Agent in CO2-Foam Flooding of Heterogeneous Carbonate Reservoirs

Retention of CO2-Foaming Agent in CO2-Foam Flooding of Heterogeneous Carbonate Reservoirs

Experimental Study of Foam Flow in Fractured Oil-Wet Limestone for Enhanced Oil Recovery

Experimental Study of Foam Generation, Sweep Efficiency, and Flow in a Fracture Network

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