Foam-EOR for Mobility Control - Results and Discussion

Part III Results and Discussion

7.5 Foam-EOR for Mobility Control

Foam can be generated by adding a surfactant solution to the injected gas, the gas phase can be made discontinuous and separated into bubbles by thin liquid films called lamella. The apparent viscosity of CO2-foam will be larger than pure CO2, therefore generation of foam will give CO2 a more favorable mobility ratio relative to oil and water, divert flow to increase sweep and add a viscous component to the oil displacement process. Foam as mobility control may improve conformance control and reduce channeling in high-permeability porous media.

As the experimental data in Figure 16 clearly demonstrates, CO2-foam significantly increased the oil recovery rate compared to pure CO2 in terms of PV injected. The final recovery, however, was not increased in the studied systems because foam does not increase the microscopic displacement efficiency compared with pure CO2. The mechanism resulting in the accelerated oil recovery during CO2-foam was the reduction in fracture conductivity that generated a significant differential pressure across the system and added a viscous component to the oil recovery process, in addition to diffusion. A conceptual numerical model, used to simulate foam by decreasing the fracture conductivity, reproduced the experimental data shown in Figure 18, and is discussed in more detail in Paper 6.

Figure 18. CO2-foam injections accelerated oil recovery compared to pure CO2

injections in fractured systems. CO2-foam injections in fractured systems (black indicators) was more efficient than pure CO2 injections in fractured systems (blue).

Most efficient was CO2 injections in unfractured systems (red). The simulation data showed an increasing oil recovery efficiency as fracture permeability decreased.

A sequential CO2 injection strategy was adopted in Paper 5 with injection of pure CO2

before CO2-foam injection. The initial oil production rate decreased rapidly in fractured systems during pure CO2 injections, and the injection was switched to CO2 -foam injection after 1-2 PV of pure CO2. The CO2-foam added a viscous component to the oil displacement process that increased oil recovery rates and final recoveries in all experiments. The increased oil recovery efficiency with foam injections in core samples (Rørdal chalk and Edwards limestone) compared to pure CO2 is shown in Figure 19. An accelerated oil recovery during CO2-foam was observed in both chalk and limestone, but was more pronounced in limestone. Larger pores and less permeability contrast between fracture and matrix in limestone reduced the entry pressure needed for viscous diversion and invasion of pores and may explain the more pronounced effect observed from CO2-foam injection in limestone compared to chalk.

Figure 19. A sequential CO2 injection strategy, where co-injection of CO2 and surfactant generating CO2-foam was initiated after 1-2 pore volumes of pure CO2

injection, accelerated oil recovery in chalk and limestone rock material. The EOR-effect was higher in limestone, which was likely due to the properties of the rock material.

Tertiary CO2 and CO2-foam injections were performed in strongly water-wet Rørdal chalk samples investigated in Paper 4. Additional oil recovery by tertiary CO2 and CO2 -foam injections after waterfloods was up to 15 %OOIP, depending on the efficiency of the preceding waterflood. Figure 20 shows a comparison of development in oil recovery during tertiary CO2 and CO2-foam injection in two core samples with similar waterflood oil recovery of 60 %OOIP. Mobility control by foam accelerated the oil production rate considerably: all additional oil was produced within 0.3 PV injected and reduced the amount of CO2 needed during CO2-EOR by more than 1 magnitude compared to pure CO2 injection.

CHALK FRACTURED CO₂ LIMESTONE FRACTURED CO₂ CHALK FRACTURED CO₂+FOAM LIMESTONE FRACTURED CO₂+FOAM CHALK UNFRACTURED CO₂ LIMESTONE UNFRACTURED CO₂

Figure 20. Tertiary CO2-foam injection and tertiary pure CO2 injection was performed in two fractured strongly-water-wet core samples with similar waterflood oil recovery of 60%OOIP. Oil recovery was accelerated and reduced the amount of CO2 injected by more than 1 magnitude to reach final end point oil recovery with CO2-foam compared to pure CO2 during the tertiary injection.

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

0.00 0.05 0.10 0.15 0.20

0 1 2 3

Normalized Oil Production Rate [0-1]

CO2-EOR [fraction OOIP]

Pore Volume Injected

FOAM TERTIARY CO2 TERTIARY FOAM RATE CO2 RATE

8 Conclusions

This Thesis focused on two main objectives: 1) Establish uniform and stable wetting preferences in outcrop core material, and, 2) Investigate CO2-EOR in fractured reservoirs and evaluate the influence of wettability. The main conclusions are listed below.

Laboratory core size experiments may provide useful information regarding EOR-efforts to improve the water-wetting state of the rock surface to increase the potential for spontaneous imbibition of water from fractures into matrix. A wetting preference with a given end point saturation for spontaneous imbibition was established in a rock/oil/brine system with the following method:

1. A dynamic aging technique using crude oil established uniform, less water-wet preferences in originally strongly water-wet outcrop chalk samples.

2. By varying the initial water saturation and the length of the aging period a range of different wetting preferences, shown to be stable over several flooding cycles, was established.

3. A wetting test cycle should be performed to evaluate the wetting preference in terms of wetting index and stability. The aging parameters can be adjusted to induce different wetting preference, which are strongly influenced by rock type, crude oil composition and brine composition.

Implementation of EOR-strategies to increase the potential for spontaneous imbibition of water from fractures to matrix are of particular importance in fractured reservoirs with low waterflood recovery. Experimental studies showed that sulfate enriched waterfloods may be an attractive EOR-method to improve the water-wetting state of the rock surface. Key observations from sulfate enriched waterfloods were:

9 Sulfate enriched brine increased spontaneous imbibition and concomitant oil recovery.

9 The EOR-efficiency depended on rock type, fluid composition, wettability index and temperature.

9 The oil composition affected the degree of wettability alteration.

Laboratory evaluation of secondary, miscible CO2 injections for EOR in fractured systems demonstrated a very efficient displacement process in terms of final oil recovery, up to 96 %OOIP was recovered. The amount of additional oil recovery during tertiary CO2 injection after waterfloods depended on the efficiency of the preceding waterflood. The oil recovery process was diffusion dominated with low production rates from the onset of CO2 injection, rapid breakthrough of CO2 and a long tail production. The following parameters and conditions were observed to decrease the oil recovery efficiency:

9 Increasing water saturation.

9 Increasing diffusion length.

9 Increasing fracture permeability.

9 More heterogeneous rock material and higher tortuosity systems.

9 Oils with heavier hydrocarbon components.

Foam as EOR-mobility control in fractured systems improves conformance control and reduce CO2 channeling in high permeable fractures in porous media. The following observations were made:

9 Low oil recovery in fractured systems was significantly improved with foam injection, which added a viscous component diverting CO2 from the fractures into the matrix.

9 Experimental EOR-Foam injection have the following important characteristics compared to pure CO2 injection: i) accelerated oil production, ii) increased total oil recovery, iii) a more effective displacement (less CO2 needed), and, iv) enhanced concomitant storage of CO2.

9 Future Perspectives

The Reservoir Physics Research Group at the Department of Physics and Technology, University of Bergen is currently managing an up-scaling project that uses laboratory data and field pilot tests to prepare for a full-scale CO2-foam field test. Reservoir cores was cleaned and restored to reservoir conditions. Preliminary results show that tertiary flooding by pure CO2 was less efficient than expected: CO2 breakthrough from the cores occurred early and significant volumes of supercritical CO2 were required to reach the residual oil saturation. Poor macroscopic sweep in the core plugs was caused by large heterogeneities, e.g. micro fractures and vugs, present in the carbonate core material and identified by CT imaging. CO2-foam floods were implemented as a strategy to reduce the volume of CO2 injected, and to increase the rate of hydrocarbon recovery. Co-injections of CO2 and surfactant solution to create foam were performed as a tertiary EOR method directly after waterflooding or after pure CO2 floods in an integrated recovery strategy. Foam flooding increased tertiary oil recovery and maintained high hydrocarbon production rates for a longer duration of time than pure CO2. The current focus is to develop a strategy to maximize oil recovery in laboratory experiments in reservoir cores at reservoir conditions with the following objectives: 1. Develop an efficient injection strategy to accelerate oil production and minimize pore volumes of CO2 injected. 2. Screening of surfactants in reservoir rock/oil/brine system to maximize production and minimise cost.

In-situ imaging by use of X-ray computed tomography (CT), magnetic resonance imaging (MRI), Nuclear Tracer Imaging (NTI) and positron emission tomography (PET) can provide additional information about dynamic fluid flow in porous media that may not be obtained from pressure measurements and material balance only. Paper A presents a combined PET-CT imaging of flow processes within porous rocks to quantify the development in local fluid saturations. The same technique could be used to obtain information about in-situ foam generation in fractures by tracing the surfactant water phase and monitor local saturation changes.

Nuclear Magnetic Imaging (NMR) can be used to measure the wettability preference in porous media based on surface relaxation time. The volume of a pore can be divided into a bulk area and a thin surface area. The molecules in the thin surface layer will have a faster relaxation time compared to the molecules in the bulk area.

The different relaxation time for oil and water in porous media can provide

information about wetting conditions (Paper B). A further development of this method to use during EOR-efforts to induce more water-wet states would add valuable information about the laboratory induced wettability, especially at near-neutral wet preferences where the Amott-Harvey method is insensitive.

History match of experimental core data should be performed when building numerical models. These models can be used to simulate EOR injection strategies in up-scaled system to reduce time consuming and expensive laboratory work. A conceptual model is described in Paper 6 and could be further developed to investigate the influence of different recovery mechanisms such as diffusion and gravity in larger matrix block size.

Nomenclature

EOR enhanced oil recovery FCM first contact miscibility MCM multi contact miscibility MMP minimum miscibility pressure NSCO north sea crude oil

Swsp end point water saturation for spontaneous imbibition of water Swsp end point water saturation for spontaneous imbibition of oil Sg gas saturation SWW strongly water-wet NNW near neutral-wet

OW oil-wet

SFB synthetic formation brine SSW synthetic seawater

SSW-0S synthetic seawater added no sulfate

SSW-4S synthetic seawater added four times the sulfate concentration found in seawater

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