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Asphaltene deposition and plugging
After precipitation, asphaltene can remain as a suspended solid in the oil or deposit onto the rock. Here, the term precipitation corresponds to the formation of a solid phase from thermodynamic equilibrium and deposition means the settling of solid particles onto the rock surface. Deposition will induce alteration of wettability (from water-wet to oil-wet) of the rock and plugging of the formation. These aspects have been known for a long time and are the subject of many recent investigations. This section reviews the investigations and laboratory observations of these aspects.
Measurements of the deposition and plugging effects were performed by Piro et al. in sand packs and by Turta et al., Minssieux, and Ali and Islam in cores to study asphaltene deposition and the subsequent effect of permeability reduction. Yeh et al., Kamath et al., and Yan et al. performed core displacements to investigate the effect of wettability alteration caused by deposition and its subsequent effect on the recovery.
Deposition and plugging
Asphaltene deposition in porous media exhibits similarities with the deposition of fines. The main phenomena are:
- Surface deposition
- Plugging deposition
Piro et al. used asphaltene precipitates collected from a field in northern Italy or induced by diluting two crude oils with n-heptane. The diluted mixture of crude oil with a given concentration of precipitate was injected into sand packs, and the concentration of asphaltene precipitate at the outlet was measured. The deposited amounts were calculated by difference.
Minssieux performed comprehensive core experiments for three crude oils from different parts of the world (France, North Africa, and North America) and four types of cores:
- Three sandstone cores with different permeabilities and clay contents
- Core from the Algerian Hassi Messaoud field, which suffers strong asphaltene-precipitation problems
Asphaltene precipitates were obtained by diluting crude oils with n-heptane. Pressure drops across the core were measured to determine the permeability reduction caused by asphaltene deposition. The amounts of deposited asphaltene along the core were estimated with a pyrolysis technique.
Ali and Islam performed core tests with crude oils from the United Arab Emirates. Crude oil with 3 wt% of asphaltene precipitate (induced by n-heptane) was injected into carbonate cores at four different rates. The pressure drops across the core were measured to determine the permeability reduction.
Turta et al. performed high-pressure core-displacement experiments with propane. Crude oils from west-central and northwestern Alberta were used. Asphaltene precipitation occurred within the core when propane mixed with the oil in the displacement process. Permeability reduction was inferred by measuring pressure drops across the core.
The first step in the deposition is the adsorption of asphaltene onto the rock surface. The adsorption of asphaltene onto different rocks has been measured extensively in static experiments that showed that the asphaltene adsorption onto different rocks can be modeled with Langmuir isotherms. Fig. 1 from Dubey and Waxman shows typical Langmuir isotherms for asphaltene adsorption on different rocks. The Langmuir isotherm equation is
- Csf = concentration of suspended solid in the oil phase
- wsa = mass of adsorbed asphaltene per mass of rock
- (wsa)max = maximum adsorbed mass fraction (the plateau in Fig. 1)
- Ka = ratio of rate constants of the adsorption/desorption reactions
Adsorption is higher for rock containing a higher content of shales. Because adsorption is a surface phenomenon, its main effect is the alteration of the rock wettability from water-wet to oil-wet.
Fig. 1 – Langmuir isotherms for asphaltene adsorption.
General deposition process
In addition to adsorption, Minssieux showed that deposition occurs because of mechanical entrapment similar to the deposition of fines in porous media. Pressure drops across the core were measured for several experiments to assess the deposition and plugging effects caused by asphaltene. Minssieux reported that the most noticeable plugging occurred in sandstones containing clays and in tight sandstones. Fig. 2 shows the reduction of oil permeability as a function of pore volume injected for sandstones with and without clay. Fig. 3 shows the permeability reduction for tight sandstone. Minssieux also used the pore-blocking model of Wojtanowicz et al. to analyze the experimental results.
Fig. 2 – Clay influence on plugging evolution.
Fig. 3 – Plugging evolution in a tight sandstone.
Ali and Islam combined a model for adsorption with the model of Gruesbeck and Collins for the entrainment and deposition of fines in porous media to analyze their experimental results. Gruesbeck and Collins assumed that the porous medium could be divided into two parallel pathways: small pore sizes, in which plug-type deposits occur and can eventually be plugged completely, and larger pore sizes, in which surface nonplugging deposits occur. Particles could be mobilized from the surface deposits if the fluid velocity exceeds a critical value. Fig. 4 illustrates this concept.
Fig. 4 – Parallel pathway model for deposition.
For nonpluggable pathways,
whereas for pluggable pathways,
- Ca = concentration of precipitated asphaltene in weight percent
- uc = critical speed required to mobilize surface deposit asphaltene
- unp = fluid velocity in nonpluggable pathways
- σnp = volume fraction of deposited asphaltene in nonpluggable pathway
- σp = volume fraction of deposited asphaltene in pluggable pathway
- α, β, χ, and γ = model parameters
Gruesbeck and Collins gave empirical correlations for calculating up and unp from u, as well as the permeabilities of pluggable and nonpluggable pathways as functions of the volumes of deposited asphaltene. Eq. 2 implies that the deposited asphaltene in nonpluggable pathways is mobilized if the velocity, unp, is greater than the critical velocity, uc. Ali and Islam developed a 1D, single-phase flow simulator with the Gruesbeck and Collins deposition model. They identified three regimes for asphaltene deposition and plugging depending on the flow rate:
- Monotonous steady state
- Quasisteady state
- Continuous plugging
Fig. 5 shows the experimental results and the match obtained with the model described in Eqs. 2 and 3. At low flow rates (monotonous steady-state regime), the permeability reduction took place in a monotonous fashion. At intermediate flow rates (quasisteady-state regime), initial reduction in permeability was observed until a minimum was reached. After reaching this minimal value, the trend was reversed with an increase in permeability. Ali and Islam attributed this increase to the mobilization of asphaltene deposited in nonpluggable pathways. At higher flow rates (continuous-plugging regime), the permeability reduction began late in the injection process but was very rapid once begun.
Fig. 5 – Effect of flow rates on permeability reduction.
- Ea = volume of deposited asphaltene per bulk volume of rock
- vc = critical interstitial velocity for surface deposition
- vo = interstitial oil velocity ( = uo/Φ)
- α, β, γ, η are model parameters
The separation of pathways into pluggable and nonpluggable has been eliminated. The last term in Eq. 4 represents the plugging deposit and is set to zero if the average pore throat diameter is greater than a critical pore throat diameter (i.e., there is no plugging deposit if the pore throat is large).
The porosity occupied by the fluid is
where Φ0 is the initial porosity. The reduction in permeability is calculated from
- k0 is the initial permeability
- fp is the porous medium particle transport efficiency factor.
Wang and Civan developed a 1D, three-phase, four-pseudocomponent simulator that incorporates the previous deposition and plugging model. They showed that their model could match some of the core deposition experiments by Minssieux and Ali and Islam.
Kocabas and Islam extended the model of Ali and Islam to the analysis of deposition and plugging in the near-wellbore region. Leontaritis also developed a single-phase radial model to analyze the near-well pressure behavior when asphaltene deposition and plugging occur. Ring et al. described a three-component, thermal reservoir simulator for the deposition of waxes in which only surface deposition is considered. Nghiem et al. have incorporated in a 3D compositional simulator both a thermodynamic single-component solid model for asphaltene precipitation and a deposition model based on adsorption and plugging deposit. A resistance factor approach was used to model permeability reduction caused by asphaltene deposition. Qin et al. proposed a method for compositional simulation based on similar approaches.
The alteration of formation wettability caused by asphaltene deposition has been the subject of numerous investigations. Asphaltene adsorption onto the rock surface is the main factor for wettability alteration from water-wet to oil-wet. Collins and Melrose, Kamath et al., Clementz, Crocker and Marchin, and Buckley et al. described the change of formation wettability from water-wet to mixed-wet or oil-wet on adsorption of asphaltene onto the rock surface:
- Clementz discussed the permanent alteration of core properties after asphaltene adsorption.
- Collins and Melrose showed that asphaltene adsorption is reduced but not eliminated by the presence of water films on water-wet rock.
- Crocker and Marchin and Buckley et al. studied asphaltene adsorption for different oil compositions and the corresponding degree of wettability alteration.
- Yan et al. performed injection of asphaltenes (obtained for diluting crude oils from Wyoming and Prudhoe Bay with n-hexane) into Berea core.
After the displacements, imbibition tests were performed to determine changes in core wettability. They showed that the amount of adsorbed asphaltene is dependent on the ions present in the brines (in this case Na+, Ca2+, and Al3+) and that adsorption increases with an increase in ion valency. The highest adsorption occurred with Al3+ in the brine. Significant changes in wettability of the sandstone core were observed after asphaltene adsorption.
Morrow reviewed the effect of wettability on oil recovery. Wettability has been shown to affect:
- Relative permeabilities
- Irreducible water saturation
- Residual oil saturation
- Capillary pressures
- Electrical properties
The alteration of relative permeabilities and endpoints has the strongest influence on displacement processes.
- Morrow reviewed results for core waterfloods showing that the shift toward a less water-wet condition can range from being highly adverse to highly beneficial to oil recovery.
- Huang and Holm, Lin and Huang, and Yeh et al. presented results on the implication of wettability changes on water-alternating-gas (WAG) processes.
Typical results for CO2 WAG processes indicate that the amount of oil trapped in water-wet cores (45%) was much higher than that trapped in either mixed-wet (15 to 20%) or oil-wet cores (5%).
Yeh et al. performed experiments in a capillary-tube visual cell showing the change in wettability on asphaltene precipitation by mixing a west Texas oil with CO2 and a Canadian Mitsue crude oil with hydrocarbon gas at reservoir conditions. They also carried out WAG coreflood experiments under reservoir conditions in which asphaltene precipitation occurred. The residual oil saturation after each flood was measured and compared with the value obtained in displacements with refined oils in which there were essentially no changes in wettability. For some experiments, they observed substantial reduction in residual oil saturations when wettability was altered. A wettability change from water-wet to oil-wet conditions increases the contact between oil and solvent and is responsible for a decrease in residual oil saturation.
Kamath et al. performed injection of a precipitating solvent (n-pentane or n-heptane) in cores saturated with crude oil. The plugging caused by asphaltene was assessed by measuring pressure drops across the cores. After the injection of solvent, water was injected and recovery and relative permeabilities were measured to study the effect of deposition on displacement efficiency. Three cores were used:
- Core 1 is a Berea sandstone core with permeability of 236 md and porosity of 27.9%
- Cores 2 and 3 are unconsolidated sandpack cores with permeability of 2380 and 1520 md and porosity of 32.7 and 31.3%, respectively
Fig. 6 shows the reduction in permeability with respect to the degree of asphaltene deposition. As expected, permeability reduction was highest for the least permeable core (Core 1) and smallest for the most permeable core (Core 2). Fig. 7 shows cumulative fractional recovery for Core 1 vs. pore volume of water injected for various degrees of asphaltene deposition. The results show an improved displacement efficiency with an increase in the deposited amounts. Similar results were obtained for Cores 2 and 3. Kamath et al. concluded from their experiments that although deposition causes permeability reduction, it may improve the sweep efficiency through the alteration of relative permeability curves and flow-diverting effects. Shedid performed similar displacement experiments on low-permeability carbonate cores instead of sandstone cores and observed substantial permeability damage with deposition.
Fig. 6 – Permeability reduction for different cores.
Fig. 7 – Cumulative fractional-oil recovery vs. PV water injected for various degree of asphaltene deposition.
The wettability alteration caused by asphaltene deposition is a complex process that is still a subject of many investigations. The degree of wettability change may not be uniform, as discussed in Al-Maamari and Buckley. The subsequent effect of wettability on relative permeabilities and oil recovery is also a complex subject. There are still unexplored areas, and the whole process is not completely understood at this time. Although the change from water-wet to oil-wet conditions caused by asphaltene precipitation may favor sweep efficiency of waterflood or WAG processes inside the reservoir, the plugging effect near the wellbore remains detrimental to oil production. Inside the reservoir, fluids can find their way around regions of deposition, but, around the wellbore, plugging will prevent flow of oil from converging to the wellbore. Remedial actions then are required to increase production.
|Ca||=||concentration of precipitated asphaltene in wt %, m/m|
|Csf||=||concentration of suspended solid in the oil phase [ppm (μg/g)]|
|Ea||=||volume of deposited asphaltene per bulk volume of rock, L3/L3|
|fp||=||porous medium particle transport efficiency factor|
|k0||=||initial permeability, L2|
|Ka||=||ratio of rate constants of the adsorption/desorption reactions|
|uc||=||critical speed required to mobilize surface deposit asphaltene, L/t|
|unp||=||fluid velocity in nonpluggable pathways, L/t|
|uo||=||oil velocity, L/t|
|vc||=||critical interstitial velocity for surface deposition, L/t|
|vo||=||interstitial oil velocity ( = uo / Φ), L/t|
|wsa||=||mass of adsorbed asphaltene per mass of rock, m/m|
|(wsa)max||=||maximum adsorbed mass fraction (the plateau in Fig. 1), m/m|
|α||=||asphaltene-deposition model parameters (Eqs. 2 and 4)|
|β||=||asphaltene-deposition model parameters (Eqs. 2 and 4)|
|γ||=||asphaltene-deposition model parameters (Eqs. 3 and 4)|
|η||=||asphaltene deposition model parameters (Eq. 4)|
|σnp||=||volume fraction of deposited asphaltene in nonpluggable pathway|
|σp||=||volume fraction of deposited asphaltene in pluggable pathway|
|χ||=||asphaltene deposition model parameters (Eq. 3)|
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