Chemical Enhanced Oil Recovery (CEOR) has come into focus as a highly effective and versatile EOR method due to recent advances in the technology. However, CEOR particularly Alkali-Surfactant-Polymer (ASP) flooding is challenging in carbonate reservoirs. The main constraints are the undesired minerals such as calcite, dolomite, anhydrite and gypsum consisted of divalent ions. The minerals complex with injected chemicals and form precipitates that cause formation damage and scale formation in wells and surface facilities. This study presents a new Acid-Alkali-Surfactant-Polymer (AASP) flooding formulation as an alternative to conventional ASP flooding. AASP included acrylic acid as a precipitation inhibitor. The new formulation was compatible with the hard brine composition of 59,940 ppm TDS (with 2762 ppm divalent ions) for 30 days at 80 °C. AASP combination also provided acceptable interfacial tension and slug viscosity required for flooding in the presence of hard brine. Additionally, more than 30% Origional Oil in Place (OOIP) was recovered in the natural imbibition tests. Injecting 0.5PV of the optimum AASP formulation slug gave 18.9% OOIP to waterflooding in the coreflood tests. Thus, AASP flooding formulation is viable for suppressing the limitations of ASP flooding in carbonate reservoirs. Although, precipitation inhibitor increases the cost of chemical slug by adding several hundred parts per million (ppm) of inhibitor, significant cost savings will be realized because of the reductions in workover jobs and associated lost of production. Further, AASP flooding formulation also eliminates the need to soften the mixing brine. This will result in expanding the CEOR application to more challenging carbonate reservoirs and reduce the softening cost for mixing water. Introduction The term Chemical EOR is used in the petroleum industry literature to refer to a class of tertiary oil recovery. Chemical EOR is usually prefered after primary recovery (or natural depletion from expansion of reservoir fluids and reservoir compaction) and secondary waterflood recovery. Waterflooding is a process whereby water is injected into a reservoir to provide pressure support and to sweep oil to the production wells. In time, the oil produced as a percentage of total liquids production will decline. Eventually the oil cut will become uneconomical. At this point, the reservoir is considered to be at residual oil saturation to waterflood. The purpose of Chemical EOR is to recover the remaining or residual oil in a reservoir that has had its mobile oil swept and produced during a waterflood. To achieve this objective, oil needs to be contacted and mobilized. Oil can be contacted by improving the sweep efficiency of injected fluids. One way to do improve sweep efficiency is to increase the viscosity of the injected fluid relative to the connate fluids. This provides a more favourable mobility ratio, prevents viscous fingering, and helps to overcome reservoir heterogeneities (Manrique et al., 2010; Al-Mjeni et al., 2011; Manrique et al., 2006). Traditionally, sandstone reservoirs have been the most suitable candidate for chemical EOR applications. However, limited numbers of CEOR application are found in carbonate reservoirs throughout the last decades. The reason is high clay content which cause significant adsorption of surfactant and polymer. Dolomite, anhydrite and gypsum often occur in carbonate reservoirs. These minerals cause alkali consumption and formation of precipitates. Unlike sandstones which are homogeneous, carbonate reservoirs are generally complex in petrophysical characteristics. Therefore, chemical enhanced oil recovery is considered as, less effective in carbonate reservoirs (Manrique et al., 2006; Taber et al., 1997).
The integrity of well construction plays an important role to recover the hydrocarbons from subsurface to surface safely and economically. The poor cement integrity behind the casing becomes the cause of gas migration and ultimate well abandonment. The lower Indus basin of Pakistan has the majority of gas producing wells and some of them are plugged due to poor cementing. This is caused by the substantial decrease in the performance of cement slurry with increase in temperature as a function of depth. Therefore, it is essential to improve the API properties of cement slurry at high temperature for minimizing fluid loss and preventing the gas migration. For this purpose, different types of polymer have widely been used as the additives in cement slurry, but those polymers show thermal thinning behavior above 158 °F temperature. Polymers have also been modified by adding chemicals to improve their thermal stability range. However, the addition of chemicals affects the properties of other additives and increases the cost of cementing operation. This paper presents the incorporation of Hydroxypropylmethylcellulose (HPMC) cellulose type polymer in cement slurry which acts as a thickener, film foamer and water retention agent. It is capable of increasing the viscosity at elevated temperature. The viscosity of HPMC solutions was determined experimentally at different temperatures ranging from 86 °F to 212 °F with respect to shear rates. The HPMC polymer showed remarkable rheological properties as a thermal thickener at 194 °F. HPMC solution was then combined with cement slurry to evaluate its API properties such as rheology, fluid loss, free water settling, thickening time and transition time at 194 °F. The experimental results showed that HPMC based cement slurries have significant rheology, minimal fluid loss, zero free water, extended thickening time. The transition time of slurries was less than 45 minutes which is considered as the excellent cement slurry for preventing gas migration as per API standards. It is concluded that HPMC based cement slurries performed as the multifunctional additive, which successfully improved the properties of slurry and prevented the gas migration at high temperature. Hence, field application of HPMC polymer will be a prominent and a cost effective technique for the petroleum industry during cementing operation in the lower Indus basin, Pakistan.
Gas migration during primary cementing is considered as an oil and gas industrial problem for many years. Currently, the gas migration problem is mitigated using modified cellulose based polymer (synthesized with carbonates) in cement slurry at high temperature. However, there is no widely accepted single polymer that can prevent gas migration without synthesization for high temperature cementing application. This study presents an experimental investigation for prevention of gas migration through cement column during transition state of cement slurry. A natural polymer Hydroxypropylmethylcellulose (HPMC) is used for the first time ever as a cement additive to achieve desire prevention, which is stable at high temperature. The gas migration through cement slurry was determined using Cement Hydration Analyzer (CHA). HPMC was found to develop an impermeable barrier for prevention of gas migration. The experimental results showed that HPMC based cement slurry was gas tight as pore pressure remains low as 16 psi with constant gas injection of 150 psi for continues 08 hours. Further, API properties of cement slurries were determined using 0.20 to 0.50 gallon per sack of HPMC. The test results showed 04 to 06 hours thickening time, less than 30 minutes transition time, low fluid loss and high compressive strength at 190 °F. It is concluded that HPMC prevents the gas migration and significantly improves the API properties of cement slurry. In field applications, the presented HPMC polymer can simplify the design of cement slurry and prevent gas migration through cement slurry at high temperature.
Mobility control is one of the most important parameters in chemical enhanced oil recovery (CEOR). Hydrolyzed polyacrylamide (HPAM) polymer, the standard mobility-control agent, is often degradable and causes poor sweep efficiency under changing shear rates and at temperatures above 140 °F. Under these conditions, HPAM solution loses more than 90% of its viscosity and is unable to sustain appropriate viscosity necessary for residual oil displacement. Therefore, a wormlike micellar (WLM) solution was developed as a substitute mobility polymer for CEOR applications. The WLM solution is composed of chains, bonded by electrostatic forces, which can deform and reform rather than permanently breaking down when subjected to high shear rates and temperature fluctuations. In this study, two compositions of WLM solutions were chosen and prepared in the laboratory. For each of these two solutions, their effectiveness was determined by comprehensive thermal compatibility tests; interfacial tests (IFT); and rheological tests to evaluate the impact of concentration, shear rates, salinity (NaCl = 3.5%, CaCl2 = 0.05%, and MgCl2 = 0.05%), and temperature (86 to 158 °F) on viscosity. Next, the core displacement test was performed to examine the residual oil displacement by a mixed-surfactant WLM solution (zwitterionic surfactant 1.09% w/v, R = 0.55). Test results determined that both of the tested WLM solutions showed great potential in high-salinity and high-temperature conditions. Each of the two WLM solutions was equally adaptable and unrestricted, despite differences between the components of each formulation. With the addition of salts, the WLM solutions were highly tolerant over the entire range of shear rates. At 158 °F, the thermal degradability of WLM solutions was less than HPAM polymer. In addition to this, IFT between crude oil and WLM solution was also observed to be very low compared to the typical water-and-oil system. Moreover, the WLM solution produced an additional oil recovery of 10.9% beyond secondary recovery during the coreflooding test. Hence, the results supported WLM solutions to be potential mobility control for CEOR. WLM solutions have been successfully shown to perform beyond the salinity, temperature, and shear-rate limitations of HPAM polymers. This makes WLM solutions more flexible, not only for EOR applications, but also for well completion, well stimulation, and for coiled-tubing cleanout processes following gravel-pack operations.
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