Water Production In Oil Fields Research Articles

Water shutoff treatment of low permeable reservoirs by in situ polymerization: laboratory scale development and verification through core flow experiments

Excessive water generation in oil reservoirs poses economic challenges, diminishing hydrocarbon yield and incurring additional costs for water management. This study focuses on enhancing reservoir conformance control, particularly in low-permeability zones with high water production, where traditional gel-based methods face limitations. The goal is improved penetration into narrow fractures and effective sealing of water-inflow zones through in situ polymerization and sequential cross-linking. The study systematically optimized key polymerization parameters, including initiator/monomer ratios, initiator types, and environmental conditions. Core flooding tests demonstrated a significant 17% increase in original oil recovery, alongside a substantial reduction in permeability. Analytical techniques such as CT scans, thin section scans, SEM, and EDS were employed to assess gel distribution within pores and penetration rates. This in situ polymerization and gelation approach show promise in addressing water production challenges, offering enhanced recovery, and adapting well to diverse reservoir conditions. The comprehensive optimization of polymerization parameters and the use of advanced analytical methods contribute to the study’s potential impact on mitigating economic and operational issues associated with excessive water production in oilfields.

Experimental characterization of colloidal silica gel for water conformance control in oil reservoirs

High water production in oil fields is an area of concern due to economic issues and borehole/wellhead damages. Colloidal gels can be a good alternative to polymers to address this as they can tolerate harsh oil reservoir conditions. A series of bottle tests with different silica and NaCl concentrations were first conducted. The gelation time, cation valence, rheology, and viscosity were investigated to characterize the gels. The applicability of solid gels in porous media was finally inspected in a dual-patterned glass micromodel. Bottle test results showed that increasing NaCl concentration at a constant silica concentration can convert solid gels into two-phase gels and then viscous suspensions. Na+ replacement with Mg2+ resulted a distinctive behaviour probably due to higher coagulating ability of Mg2+. Rheology and viscosity results agreed with gelation times: gel with shortest gelation time had the highest viscosity and storage/loss modulus but was not the most elastic one. Water injection into glass micromodel half-saturated with crude oil and solid gel proved that the gel is strong against pressure gradients applied by injected phase which is promising for water conformance controls. The diverted injected phase recorded an oil recovery of 53% which was not feasible without blocking the water zone.

Evaluation and X-Ray tomography analysis of super-absorbent polymer for water management in high salinity mature reservoirs

The oil reservoirs in the Perm Krai region in Russia are characterized by high formation water salinity (200–230 g/l) and low reservoir temperature (25–30 °C). Currently, about 75% of their remaining reserves have a water cut of more than 50%. Super absorption polymers, also called preformed particle gels (PPGs), have been widely applied to control water production in oilfields; however, no work has been carried out in this area. Based on the Perm Krai reservoir characteristics, we synthesized a new PPG using a free radical polymerization method through a thermal imidization process. The swelling kinetics and equilibrium of the acquired PPG have been evaluated under different types and concentrations of brines. Core-flooding experiments were conducted using formation sandstone cores to compare the plugging capacity of the new PPG with a traditional polyacrylamide solution. The change in the pore space of the cores was analyzed using X-ray tomography to explore the conformance control mechanisms resulted from PPG treatment. The results show that the PPG can be used in the target oil reservoirs and can plug the pore space of the core six times more than traditional polyacrylamide, indicating that the PPG can efficiently plug large channels and redistribute the water flow to a small pore space.

Performance of PAM/PEI gel system for water shut‐off in high temperature reservoirs: Laboratory study

ABSTRACTA polymer gel is one of the common remediate methods to either reduce or totally block excessive water production in oilfields. Some systems demonstrated an excellent performance in treating the problem like polyacrylamide tert‐butyl acrylate (PAtBA)/polyethylenimine (PEI). In this study, polyacrylamide (PAM) was introduced as a cheap alternative to PAtBA that can tolerate high salinity reservoirs. The thermal stability of the PAM/PEI polymeric gel in saline water was examined at 150°C (302F). Samples prepared in sea water showed better stability compared with distilled and field water. Dynamic rheology and core‐flooding experiments were used to evaluate the PAM / PEI gel system at high temperatures. NaCl and NH4Cl were evaluated as a possible retarders for delaying the gelation time in order to achieve a successful placement. NH4Cl was found to be more effective retarder. Core‐flooding tests were conducted in sandstone and carbonate cores. The subject polymer gel was injected at rates typical of those in field applications. The injectivity of PAM/PEI was tested in Berea sandstone cores with initial permeability of ∼45 mD. The post‐treatment of the system showed a permeability reduction of ∼94% for a period of two weeks. The injectivity in low permeability carbonate cores required more retardation compared with the injectivity in sandstone cores. The gel reduced the permeability to brine in Indiana limestone core by 99.8% for more than 5 months. Rheology of cured gel samples indicated that the gel strength needs about one day of curing in the core for the strength to stabilize. © 2015 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2015, 132, 41869.