Using Laboratory Flow Experiments and Reactive Chemical Transport Modeling for Designing Waterflooding of the Agua Fria Reservoir, Poza Rica-Altamira Field, Mexico
- Peter Birkle (Inst. Investigaciones Electr.) | Karsten Pruess (Lawrence Berkeley Laboratory) | Tianfu Xu (Lawrence Berkeley Laboratory) | Rufino A. Hernandez Figueroa (Pemex E&P) | Marina Diaz-Lopez (PEMEX) | Enrique Contreras-Lopez (Instituto de Investigaciones Elctricas IIE)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- December 2008
- Document Type
- Journal Paper
- 1,029 - 1,045
- 2008. Society of Petroleum Engineers
- 5.4.1 Waterflooding, 5.6.1 Open hole/cased hole log analysis, 5.9.2 Geothermal Resources, 6.5.2 Water use, produced water discharge and disposal, 4.3.1 Hydrates, 5.2 Reservoir Fluid Dynamics, 3.2.4 Acidising, 1.2.3 Rock properties, 5.5.2 Core Analysis, 1.2.2 Geomechanics, 4.1.5 Processing Equipment, 5.6.4 Drillstem/Well Testing, 4.3.4 Scale, 1.6.9 Coring, Fishing, 5.2.2 Fluid Modeling, Equations of State, 4.1.2 Separation and Treating, 3 Production and Well Operations, 5.3.1 Flow in Porous Media, 5.5 Reservoir Simulation, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc)
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Waterflooding for enhanced oil recovery requires that injected waters must be chemically compatible with connate reservoir waters, in order to avoid mineral dissolution-and-precipitation cycles that could seriously degrade formation permeability and injectivity. Formation plugging is a concern especially in reservoirs with a large content of carbonates, such as calcite and dolomite, as such minerals typically react rapidly with an aqueous phase, and have strongly temperature-dependent solubility. Clay swelling also can pose problems. During a preliminary waterflooding pilot project, the Poza Rica-Altamira oil field, bordering the Gulf coast in the eastern part of Mexico, experienced injectivity loss after 5 months of reinjection of formation waters into Well AF-847 in 1999. Acidizing with hydrochloric acid (HCl) restored injectivity.
We report on laboratory experiments and reactive-chemistry modeling studies that were undertaken in preparation for long-term waterflooding at the Agua Fría reservoir. Using analogous core plugs obtained from the same reservoir interval, laboratory coreflood experiments were conducted to examine the sensitivity of mineral-dissolution and -precipitation effects to water composition. Native reservoir water, chemically altered waters, and distilled water were used, and temporal changes in core permeability, mineral quantities, and aqueous concentrations of solutes were monitored. The experiments were simulated with the multiphase, nonisothermal reactive transport code TOUGHREACT™ (Lawrence Berkeley National Laboratory, Berkeley, California, 2004), and reasonable-to-good agreement was obtained for changes in solute concentrations. Clay swelling caused an additional impact on permeability behavior during coreflood experiments, whereas the modeled permeability depends exclusively on chemical processes. TOUGHREACT was then used for reservoir-scale simulation of injecting ambient-temperature water (30°C, 86°F) into a reservoir with initial temperature of 80°C (176°F). Untreated native reservoir water was found to cause serious porosity and permeability reduction because of calcite precipitation, which is promoted by the retrograde solubility of this mineral. Using treated water that performed well in the laboratory flow experiments was found to avoid excessive precipitation and allowed injection to proceed.
The Poza Rica-Altamira oil-field forms part of the Chicontepec region, located in the eastern part of central Mexico in the state of Veracruz, approximately 5 km from the town of Poza Rica and 250 km NE from Mexico City (Fig. 1). The thick, low-permeablity accumulation of Paleocene sediments within the Chicontepec paleochannel contains an estimated 139 billion bbl [22 billion m3] of original oil in place and 50 Tcf [1.4 Trillion m3] of gas (Williams 2003). A total of 951 production wells were completed from 1951 to 2002, with initial production rates on the order of 70 to 300 (BOPD) [11 to 48 m3/d].
Recently, Pemex initiated an aggressive strategy to increase field production from an average of 2,500 BOPD [397 m3/d] and 12 MMcf/D [344,000 m3/d] of gas in 2002 to reach 39,000 BPD [6,200 m3/d] and 50 MMcf/D [1.4 million m3/d] of gas in 2006 (Tapia et al. 2004). Central to the success is the construction of high-productivity wells and waterflooding as part of an enhanced-oil-recovery program.
During a preliminary waterflooding pilot project in 1999, a maximum injection rate of 4,000 B/D was applied to Well AF-847. Fig. 2 shows the pressure and water-injection rate during the initial 5 months of the injection experiment. Increasing injection rates from 240 to 4,000 B/D caused a pressure rise from 50 to 230 bar, whereby initial pressure conditions were not recovered during intercalated falloff tests (Q=0 B/D). After 167 days of injection, the well capacity decreased to 1,920 B/D. Acidizing with 15% HCl restored the primary injectivity of the well partially, as injection rate increased to 2,500 B/D.
This paper presents selected results from a study undertaken to develop guidelines for an appropriate treatment of reservoir water from the Poza Rica collector station (Central de Almacenamiento y Bombeo Poza Rica) before its injection into the Chicontepec reservoir of the Agua Fría field. Specific issues addressed include the following:
- Define mechanisms and chemical, physical/mechanical, and biological processes that may cause plugging of the injection interval.
- Characterize materials causing scale formation in fractures and pores.
- Design a practical treatment procedure for reservoir water for its injection into the oil reservoir.
In general, the design of a treatment process for injection water shall support the waterflooding project of the enhanced-oil-recovery program, especially to prevent installation damage and reservoir scaling of the Chicontepec reservoir of the Agua Fría field. This paper presents results of laboratory flow experiments at core scale and numerical simulations with the TOUGHREACT code for chemically reactive flows to reconstruct potential chemical and physical processes during the injection of untreated and treated connate formation water into the Agua Fría oil reservoir.
|File Size||9 MB||Number of Pages||17|
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