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Abstract This paper examines some of the challenges related to the application of alkali-surfactant-polymer (ASP) flooding in high-temperature carbonate oil reservoirs. In particular, the calcium sulfate minerals gypsum (CaSO4.2H2O) and anhydrite (CaSO4) often present in small quantities in carbonate formations, have long been recognized as obstacles to chemical flooding. We illustrate these challenges for an 83 ºC carbonate field, initially containing evaporitic water, flooded with an ASP slug mixed in seawater, and followed with a polymer drive in diluted seawater. Introduction Carbonates, and in particular high-salinity, high-temperature carbonates, represent a significant fraction of remaining oil reserves, but have long been considered a challenging target for chemical enhanced oil recovery (EOR). Individual concerns relating to temperature, calcium, and salinity tolerance of EOR polymers (Zaitoun and Potie, 1983; Moradi et al., 1983; Levitt et al., 2011(A&B)) and surfactants (Adkins et al, 2010; Bourrel and Schechter, 1988; Akstinat, 1985) have been extensively studied. Concerns relating to the carbonate milieu, on the other hand, are diverse and may require specific knowledge of the target reservoir, however, examined individually, can often be mitigated. This paper focuses primarily on frequently encountered challenges related to the geochemical interactions between carbonates and EOR chemicals. We illustrate these challenges for an 83 ºC carbonate field, initially containing evaporitic water, flooded with an ASP slug mixed in seawater, and followed with a polymer drive in diluted seawater. Geochemical equilibria of carbonate reservoirs The transport of EOR surfactants, polymers, and alkalis, almost all of which contain anionic moieties that are highly sensitive to divalent cations, through carbonate formations in which massive amounts of calcium and magnesium are present as calcite (CaCO3) or dolomite (CaMgCO3) is, at first glance, alarming. However the solubility of calcite is low enough (no more than around 10 ppm of calcium will dissolve under non-acidic conditions) that effects on surfactant and polymer are almost negligible. Palandri and Reed (2001) posit that all reservoirs are likely in equilibrium with calcite, indicating that calcium uptake due to equilibrium with calcite would be equally relevant for sandstone reservoirs. In the presence of significant quantities of sodium carbonate (Na2CO3), the equilibrium will be shifted such that calcium uptake from calcite dissolution will be essentially nil. Disordered dolomite may also be in equilibrium with formation waters, however its solubility is equally insignificant with respect to EOR chemicals. The calcium sulfate minerals, gypsum (CaSO4.2H2O) and anhydrite (CaSO4), often present in small quantities in carbonate formations, have however long been recognized as obstacles to chemical flooding. The predominance of each mineral as well as calcium and sulfate concentrations of desulfated seawater in equilibrium with the relevant mineral is presented in Figure 1. Gypsum is the equilibrium mineral present below around 45 ºC, at which point anhydrite becomes the equilibrium mineral form. Solubility of calcium sulfate minerals decreases monotonically with temperature, but increases with salinity. Calcium uptake from calcium sulfate mineral dissolution may thus range from as low as a couple of hundred parts-per-million (ppm) for fresh water injected into high-temperature formations, to around 2,000 ppm for a high-salinity brine injected into a low-temperature reservoir. This may have a significant effect on surfactant phase behavior as well as polymer viscosity, although this can be explicitly determined and mitigated (Levitt et al. 2009).
- North America > United States > Texas (0.94)
- Asia (0.93)
- Europe (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Asia > China > Gansu > Yumen Field (0.99)
The Effect of a Non-negative Salinity Gradient on ASP Flood Performance
Levitt, David B. (Total Petrochemicals France) | Chamerois, Manuel (Total Petrochemicals France) | Bourrel, Maurice (Total Petrochemicals France) | Gauer, Pascal (Total E&P) | Morel, Danielle (Total E&P)
Abstract Several decades of research have led to general acceptance that a negative salinity gradient represents the optimal injection strategy in surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding. However, in many situations, such as when formation brine salinity is low either naturally or due to extensive waterflooding, a classical, negative salinity gradient is not feasible. In this case, other options may include the retention of a negative gradient between the slug and drive, but with the allowance of type I formation brine salinity, or a "I-III-I" gradient. We investigate how this strategy will affect flood performance in respect to a classical, negative, or "II-III-I" gradient. Corefloods and 1-D simulations are used to compare the production profiles of the two, and additional simulations examine the difficulty in capturing the tradeoff between low interfacial tension and phase trapping near the transition between type I and type III phase behavior.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract The Polymer Injection Project on the Dalia field, one of the main fields of Block 17 in deep offshore Angola, is a world first for both surface and subsurface aspects. In depth integrated geosciences and architecture study culminated, in January 2009, in the start of polymer injection in one of the Dalia water injection wells. Dalia field is a high permeability sandstone reservoir (> 1 D on average) and contains a medium viscosity oil (1 to 11 cP under reservoir conditions). The key challenges of the project were to start polymer injection: –Very early in the field development since first oil was in Dec. 2006 –With much wider well spacing than in any other project, –Under high salinity conditions (>25g/l) –With the specific logistics of a remote deep offshore area. After a very positive single well injectivity test early in 2009, additional single well injectivity tests were performed end 2009 on three Dalia wells in various configurations. They demonstrated an injectivity of the polymer solution that satisfies the Field Development requirements in term of voidage replacement, as defined in the water injection base case. During this testing period, the capacity of the logistics and surface facilities (capacity of 7 t/day) to successfully prepare the polymer solution on board the FPSO have been demonstrated after specific difficulties and issues were identified and fixed. Based on these positive results, a Phase 1 project was sanctioned and started on 8th February 2010 on the Camelia complex. Viscosified water is injected in one of the four injection lines of Dalia field (average BSW of 20% on the associated producers at beginning of Phase 1 polymer injection). By mid June 2010, more than 3 MM bbls of cumulative of polymer solution have been injected in the Camelia reservoir. The specificities of the Dalia field (large well spacing and low BSW at polymer injection start up) mean a late response if the usual EOR monitoring techniques are applied. Various monitoring options were considered to verify the injected polymer solution properties in-situ, and accelerate the sanction for a fullfield development. The studies concluded on a recommendation to drill a well to sample in-situ the injected viscosified water. Locations of the sampler well at a distance of 100m from an injector, and best timing to drill the well were based on 4D seismic data history match and waterflood performance forecast.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.54)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Block 17 > Dalia Field > Camelia Formation (0.99)
- Africa > Angola > South Atlantic Ocean > Lower Congo Basin > Block 17 > Camelia Field (0.99)