The challenge for all oil and gas companies is to produce as much oil as commercially feasible, leaving as little oil as possible trapped inside the reservoir. During the primary recovery stage, reservoir drive comes from a number of natural mechanisms. These include natural water pushing oil towards the well, expansion of the natural gas at the top of the reservoir, expansion of gas initially dissolved in the crude oil, and gravity drainage resulting from the movement of oil within the reservoir from the upper regions to lower regions where the wells are located. Recovery factor during the primary recovery stage is typically about 5-15% under such natural drive mechanisms.
Over the lifetime of a well, however, the pressure will eventually fall, and at some point there will be insufficient underground pressure to force the oil to the surface. Once the natural reservoir drive diminishes, secondary and tertiary recovery methods are applied to further increase recovery. Secondary recovery methods rely on the supply of external energy into the reservoir in the form of injecting fluids to increase reservoir pressure, hence replacing or increasing the natural reservoir drive with an artificial drive. In addition, pumps, such as beam pumps, pumps with gas lift and electrical submersible pumps (ESPs), can be used to bring the oil to the surface. Secondary recovery techniques include increasing reservoir pressure by water injection, CO2 injection, natural gas reinjection, and miscible injection, the most common of which is probably water injection. Typical recovery factor from water-flood operations is about 30%, depending on the properties of oil and the characteristics of the reservoir rock. On average, the recovery factor after primary and secondary oil recovery operations is between 35 and 45%.
While secondary recovery techniques are fairly effective, the existence of fractures and regions of highly porous or permeable rock reduce their potential effectiveness. Any gas or liquid that is injected into a well, will naturally travel the least restrictive route, thus bypassing some of the oil in the less porous or permeable regions. Thus, the overall effectiveness of the sweep is reduced by these so-called “thief zones,” which channel injection fluid directly to production wells.
In such cases, polymers are injected into the thief zones in order to block these zones, thus diverting the subsequent injection fluids to push previously unswept oil towards the production wells. Gels have been applied in enhanced oil recovery to improve the sweep efficiency, prolong the life of an oil well and maximize the recoverable oil amount by placing the gelants deep into the reservoir and blocking the high-permeability channels.
One of the difficulties involving the use of gelants to block thief zones, though, is increasing the viscosity of the gelants. Viscous gelants are difficult to pump and can shear during pumping, making it more difficult and expensive to get the viscous solutions deep into the reservoir, yet high viscosity is needed to block the thief zones. For this reason, there is considerable effort directed to delaying the further crosslinking of polymers until they have already penetrated deep into the reservoir.
Among the polymers used for such purposes, partially hydrolyzed polyacrylamide (HPAM) cross linked with Cr (III) gels have been widely used for water shutoff and sweep improvement in field applications. Other metal ions that can further crosslink polymers containing anionic sites include zirconium, titanium, iron, aluminum and combinations thereof.
Usually these metallic ions crosslink gellable polymers through the interaction with e.g., the carboxylate groups of the polymer molecules. Generally, the gellable polymers used such as, for example, polyacrylamide are of high molecular weight and contain high degrees of hydrolysis, i.e., contain 10-30 mole % carboxylate groups. However, these high molecular weight and/or high mole % carboxylate group-containing polymers gel almost instantly in the presence of the above-described multivalent metallic compounds. Such fast gelation rate renders the application of gelling compositions containing these polymers and multivalent metallic compounds not useful in many oil-field applications such as, for example, water shut-offs and permeability reductions, since the gelant crosslinks before it has had a chance to penetrate the reservoir, thus stopping its flow. Furthermore, the resulting gels typically synerese heavily in most oil-field brines, depending on reservoir temperature and the divalent cation content of the brine.
Many efforts have been directed to delaying the gelation of such polymers by adding a gelation delaying agent to the compositions. The use of ligands complexed with multivalent cations such as Al(III), Cr(III), Ti(IV) and Zr(IV) to crosslink partially hydrolyzed polyacrylamides (HPAM) has been a common practice to slow the rate of reactions of these cations with HPAM. The presence of ligands such as acetate, citrate, propionate, malonate, etc., which bind to multivalent cations, inhibit rapid interaction of the multivalent cations with the negative sites of HPAM to produce gels, thus delaying the rate of gelation.
An extensive study (Albonico 1993) performed on evaluating various retarding ligands, ranked the effectiveness of hydroxycarboxylates, dicarboxylates and aminocarboxylates on retarding the gelation rate of Cr(III) with HPAM solutions. This study showed that malonate ions are 33 times slower than acetate to gel 0.5% HE-100, a copolymer of acrylamide and sodium AMPS, at 120° C. This study ranked ascorbate to be 51 times slower than acetate under the same conditions. The authors further tested the effectiveness of various ligands in propagation of Cr(III) ions in both sandstone and carbonate formations. They concluded that malonate ions are most effective in promoting propagation of Cr(III) in porous media, preventing precipitation and thus retention of Cr(III).
While the rates of gelation of HPAM with complexes of multivalent cations are slower than for un-complexed multivalent cations, they are still not slow enough. Extensive gelation tests with complexes of multivalent cations with HPAM indicate formation of non-flowing gels within a few hours, not long enough for deep placement of the gelants before reaching the non-flowing stage. Additionally, the integrity of the stabilized package due to chromatographic separation might hinder their effectiveness of such systems in treating high permeability targets deep in porous media matrix.
Extending the gelation times from a few hours to days or weeks, is therefore, highly desirable for the placement of the gelants deep in matrix target zones. Further, a less toxic package that is very stable in various brines and at typical reservoir temperatures would also be desirable, since the increased stability will allow deeper deployment.