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Energy
X-Ray CT Investigation of Displacement Mechanisms for Heavy Oil Recovery by Low Concentration HPAM Polymers
Skauge, Arne (University of Bergen) | Shaker Shiran, Behruz (NORCE Energy) | Ormehaug, Per Arne (NORCE Energy) | Santanach Carreras, Enric (TOTAL E&P) | Klimenko, Alexandra (TOTAL E&P) | Levitt, David (TOTAL E&P)
Abstract Polymer flooding has proved to be a successful EOR method in very heavy oil reservoirs, despite failure to achieve a favorable mobility ratio even with polymer, which was originally imagined to be a necessary criterion for success based upon fractional flow theory. In a previous study (Levitt et al. 2013), we demonstrated a surprisingly high oil recovery with low concentration (and viscosity) partially hydrolyzed polyacrylamide (HPAM) polymer solutions of only 3 cP displacing a 2000 cP oil. Additional experiments with more viscous as well as non-elastic viscosifying agents demonstrated that recovery is not sensitive to viscosity, and thus cannot be understood through fractional flow theory. The scope of this paper is to understand where additional recovery comes from through visualization using CT imaging, in order to allow operative driving mechanisms to be optimized. Two long core (30 cm) flooding experiments have been performed to understand oil recovery at adverse mobility ratio. The first experiment started with waterflooding followed with polymer flooding (3 cP), while the second experiment started with polymer flooding directly. In-situ saturations were obtained by a medical CT scanner operated at high energy level, and used two X-ray sources and two array detectors simultaneously. The procedure was to perform the waterflood or polymer flood direct in the CT scanner. That will give us the finger development from early stage until a well-established channel is developed. The frontal velocity was about 1 ft/day. The displacements were further analyzed through simulations and dynamic pore scale model to understand the changes in fluid flow. CT imaging demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density. This is in agreement with observed behavior of unstable displacements involving viscoelastic fluids in Hele-Shaw cells (Bonn et al., 1995). These results suggest that elasticity may be more significant than viscosity in optimizing oil recovery under highly unstable conditions, for example with oils of ~1000 cP or higher. Presence of fingering under both water and polymer flood was also confirmed, with dominant finger diameter on the order of 1 mm (under waterflood) to 2 mm (under polymer flood). Fingers grow in thickness and length, and near the inlet they start quickly to overlap. Fingers are formed mostly in the middle of the core and fewer fingers appear near the wall of the core. CT shows that the waterflood is dominated by viscous fingering. Experimental CT data together with simulations and pore scale modelling have demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density or stabilization of the displacement front. Among other things, these results demonstrate that the assumption of capillary equilibrium is inappropriate under these conditions, and thus that fractional flow theory is poorly suited to predicting or optimizing recovery.
- Europe (1.00)
- Asia (0.94)
- North America > United States > Oklahoma (0.28)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
Abstract This is the final installment in a series of three papers examining iron mineralogy and its effect on surfactant adsorption in reservoir and outcrop rock samples. The goal of these studies is to establish best practices for obtaining surfactant adsorption values representative of those in a reduced oil reservoir, despite performing experiments in an oxidizing laboratory atmosphere. This article follows two others examining the abundance and form of iron in the reservoir and in core samples (Part I: Levitt et al., 2015), and a proposed core restoration technique utilizing iron-reducing bacteria (Part II: Harris et al., 2015). In this Part III, chemical reduction methods are examined. Surfactant retention is a leading uncertainty in economic forecasting of chemical EOR, in large part due to the order-of-magnitude effects of artifacts such as improper core preservation. The industry standard is to (a) limit atmospheric contact of cores to the extent feasible, and (b) when necessary, reduce oxidized cores using strong reducing agents such as sodium dithionite, along with buffering and chelating agents such as sodium bicarbonate and EDTA or sodium citrate. However few studies have been performed to determine whether such invasive treatments are necessary, or what unintended effects the use of such reactive chemicals may have. The most striking conclusion from these studies is the lack of clear evidence of any advantage of electrochemical reduction versus a simpler treatment with chelators such as sodium citrate or EDTA. Wang (1993) suggests that oxidation of reservoir cores leads to higher surfactant adsorption due to the reduction of clays, which yields a more negative surface charge. Static experiments with montmorillonite clay, as well as an oxidized outcrop containing significant clay and iron content, illustrate that rinsing with non-reducing agents such as sodium bicarbonate, EDTA, or sodium citrate can lower adsorption as much as a strong reducing agent such as sodium dithionite. In the case of montmorillonite, cation exchange appears to be the mechanism by which adsorption is lowered, and so NaCl alone is sufficient to lower adsorption to near-zero values. For the iron- and clay-containing outcrop material, initial measurements indicating "adsorption" far in excess of a dense bilayer were due in fact to the precipitation of sulfonate surfactant with calcium, which eluded from the dissolution of small amounts of anhydrite. An alkyl alkoxy sulfonate surfactant showed higher calcium tolerance, and did not yield "multilayer" adsorption when equilibrated with the anhydrite-containing core sample. While treatment with a citrate-bicarbonate-dithionite solution does indeed lower adsorption several-fold further, solutions of either sodium bicarbonate or EDTA are at least as effective, and sodium citrate is almost as effective. These non-reductive treatments remove small amounts (~0.1% – ~0.2% of rock mass) of Fe and Al, and fines are invariably apparent in treatment fluids, both of which suggest removal of small amounts of trivalent Fe/Al colloids. Wang (1993) suggests reduction or removal of trivalent iron from clay surfaces as a possible mechanism of lowered adsorption under electrochemically reducing conditions. These results suggest that removal of trivalent cations, with concomitant lowering of anionic surfactant adsorption, is possible with non-reductive chelators such as sodium citrate or sodium EDTA. Sodium bicarbonate is equally effective at lowering adsorption, but does not result in elution of Fe or Al, indicating that these are likely reprecipitated. PIPES buffer, which is used in biological applications for its low propensity to form ligands, lowers adsorption as much and no more than a 10% NaCl rinse, suggesting only anhydrite removal and possibly cation exchange with clays occurs. While these results suggest that non-reductive means may be used to remove artifacts introduced by core oxidation, they come with an important caveat: even rinsing with a brine solution can result in significant alteration of mineralogy. The use of chelating agents will invariably result in dissolution of any soluble minerals present such as gypsum or anhydrite, which can be an important contributor to surfactant (in particular ABS) consumption. In cases where iron removal is necessary due to polymer degradation issues, PIPES buffer is proposed for use as an alternative to bicarbonate, the latter having a greater tendency for ligand formation. The combination of borohydride and bisulfite is suggested as an alternative to dithionite as a reducing agent, resulting in more complete iron removal under some conditions, and anecdotally less tendency for polymer degradation upon subsequent oxidation, though both of these claims should be verified.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Designing and Injecting a Chemical Formulation for a Successful Off-Shore Chemical EOR Pilot in a High-Temperature, High-Salinity, Low-Permeability Carbonate Field
Levitt, David (Total) | Klimenko, Alexandra (Total) | Jouenne, Stephane (Total) | Passade-Boupat, Nicolas (Total) | Cordelier, Philippe (Total) | Morel, Danielle (Total) | Bourrel, Maurice (Total)
Abstract This article describes the formulation design, optimization, implementation, and lessons learned leading up to a successful 1-spot surfactant-polymer (SP) pilot in the Middle East. The target field is a high-temperature, high-salinity, low-permeability carbonate, and thus presents both great challenges and great potential for the application of chemical EOR technology. A surfactant-polymer (SP) formulation was optimized for these conditions based upon a novel, hydrophilicity-enhanced molecule for high-temperature, high-salinity reservoirs synthesized by Total R&D labs. Thermal stability tests, over 5000 microemulsion pipette tests, and more than 40 corefloods were performed during the screening and optimization process leading up to the 1-spot SP pilot. Additionally, a novel method was developed to optimize polymer molecular weight distribution, in order to decouple in-situ viscosity from near-wellbore injectivity. The final formulation consists of a 0.4 pore volume (PV) SP slug of 1.35% active surfactant, plus 1% clarifier, and SAV-225 polymer (SNF Floerger) in a 80 g/l brine corresponding to a hypothetical softened mixture of seawater and local aquifer water. This is followed by a polymer drive of AN-125 polymer (SNF Floerger) in softened seawater, such that a negative salinity gradient is imposed between the 230 g/l formation brine, 80 g/l SP slug, and 42 g/l seawater. The formulation was designed and implemented without need for a preflush. Residual oil saturation to chemicals (Sorc) in analog limestone cores was measured as 5%±2%, corresponding to a recovery factor (RF) of 90%±4%. Reservoir limestone contains significant heterogeneity on the core-scale, likely preventing the formation of an oil bank, and thus yielded lower recoveries (Sorc: 13%±2%, RF: 84%±4%). One-spot pilot recovery corresponded closely to recovery in analog cores (Sorc: 4%, RF = 90%, Al-Amrie et al., 2015), suggesting that the reason for the lower recovery in reservoir cores was in fact due to the short core length with respect to the mixing zone, as suggested in a previous publication (Levitt et al., 2012).
- Asia > Middle East (0.88)
- North America > United States > Montana > Roosevelt County (0.25)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)