Carbonated water injection (CWI) might be an efficient alternate to CO₂injection technique. In CWI, CO₂exists as a dissolved phase and not as a free phase; thus, it eliminates some challenges encountered in CO₂injection such as poor sweep efficiency and gravity segregation. In CWI, the density and viscosity of water become higher than normal due to the CO₂dissolution, thereby reducing the gravity segregation and channeling effect. This article is a comprehensive review on how carbonated water flooding has evolved over the time and captured salient features on the mechanisms involved in its role in enhanced oil recovery. The aspects reviewed in this article include a brief comparison of conventional CO₂injection and carbonated water injection and the benefits thereof. Solubility of CO₂in water, brine and oil phases is discussed in detail with valid correlations. A brief history of the development of CWI in the laboratory and field information is captured from 1905s to the present followed by the possible mechanisms and principle of CWI reported by various authors. This article also captured the latest findings on the beneficial effect of hybridizing CWI with smart water technologies.

Hydraulic fracturing is a widely used technology to enhance the productivity of low-permeability reservoirs. Fracturing fluids using guar as the rheology builder leaves aside residual polymer layers over the fractured surface, resulting in a restricted matrix to fracture flow, causing reduced well productivity and injectivity. This research developed a specialized enzyme breaker and evaluated its efficiency in breaking linear and cross-linked guar-polymer gel as a function of time, temperature, and breaker concentration targeting a high-temperature carbonate reservoir. The study began with developing a high-temperature stable galacto-mannanase enzyme using the “protein-engineering” approach, followed by the optimization of fracturing fluids and breaker concentrations measuring their rheological properties. The thermal stability of the enzyme breaker vis-à-vis viscosity reduction and the degradation pattern of the linear and cross-linked gel observed from the break tests showed that the enzyme is stable and active up to 120 °C and can reduce viscosity by more than 99%. Further studies conducted using a high-temperature high-pressure HT-HP filter press for the visual inspection of polymer cake quality, filtration loss rates, and cake dissolution efficiency showed that a 6 h enzyme treatment degrades the filter cake by 94–98% compared to 60–70% degradation in 72 h of the natural degradation process. Coreflooding studies, under simulated reservoir conditions, showed the severity of postfracture damage (up to 99%), which could be restored up to 95% on enzyme treatment depending on the treatment protocol and the type of fracturing gel used.

Fractured carbonate reservoirs are prone to premature water cut production at the early stage of recovery. Conventionally completed long horizontal wells, suffering from high water cut through fracture networks, need reliable and cost-effective treatment solutions to control water entry, without damaging oil-saturated segments. Protection of oil flow channels from polymer gel invasion could be a challenge in complex fractured reservoirs because of the enormity of the number of zones that may require damage protection. In this work, a chemical package system is developed, comprising three different chemical solutions. The first fluid is designed to protect the low-permeable oil-saturated zones by creating an impermeable barrier while keeping the water conductive fractures open, followed by a gelant, designed to invade, solidify, and seal off the water conductive fractures. The third treatment is designed for a complete dissolution of the protective barrier created by the first fluid. The effectiveness of this process is evaluated through a set of four core flood studies at reservoir conditions. It was observed that whereas the effective brine permeability could be reduced by 74–91%, oil effective permeability is reduced by 12–17% depending on the fracture aperture. The paper also discusses the key parameters to be addressed for successful field implementation of this technology.

A polymer flooding workflow was developed to diminish polymer degradation and minimize formation damage under high-temperature-high-salinity reservoir conditions by using a shear-thickening polymer (SAP) prepared in engineered waters. First, rock characterization, fluid-fluid analysis, and formation damage tests were conducted to shortlist the potential formulations of polymer solutions based on higher viscosity and less formation damage. Second, polymer core flooding experiments were conducted under reservoir conditions to investigate the performance of candidate polymer solutions on oil displacement efficiency (DE). For the first time, the compatibility between SAP and engineered water was systematically tested. The factors affecting bulk rheology, polymer retention, and oil DE, including polymer concentration, polymer type, salinity, and hardness, were experimentally investigated and compared with regular partially hydrolyzed polyacrylamide (HPAM). Results showed that compared with HPAM, the SAP solution led to lower formation damage and overall higher oil DE, especially in the first 0.4 pore volume of polymer injection. When using SAP prepared in twice-diluted and hardness-stripped seawater under low-salinity formation brine conditions, the DE was the highest (69.04%). The formation damage was reduced when the salinity and hardness of the base fluid were lower, whereas stripping the hardness had a more pronounced effect on reducing formation damage. The improved oil recovery potential due to the shear-thickening feature of SAP solutions and their better compatibility with engineered water compared to regular HPAM has been proven in this study. It was also found that the lower salinity and hardness of the engineered water further stimulated the enhanced oil recovery potential of SAP solutions. The contribution of this work relies on revealing how SAP prepared in different engineered waters affects incremental oil DE under harsh reservoir conditions based on experimental evidence and mechanism analysis. The novelty of this work lays the foundation for investigating the potential application of SAP on a pilot scale.

Tight gas reservoirs are finding greater interest with the advancement of technology and realistic prediction of flow rate and pressure from such wells are critical in project economics. This paper presents a modified productivity equation for tight gas horizontal wells by modifying the mechanical skin factor to account for non-uniform formation damage along with the incorporation of turbulence effect in the near-wellbore region. Hawkin’s formula for calculating skin factor considers the radius of damage as a constant value, which is less accurate in low-permeability tight gas reservoirs. This paper uses a multi-segment horizontal well approach to develop the local skin factors and the equivalent skin factor by equating the total production from the entire horizontal well to the sum of the flow from individual segmented damaged zones along the well length. Conical and horn-shaped damaged profiles are used to develop the equivalent skin used in the horizontal well productivity equation. The productivity model is applied to a case study involving the development of a tight gas field with horizontal wells. The influence of the horizontal well length, damaged zone permeability, drainage area, reservoir thickness, and wellbore diameter on the calculated equivalent skin (of a non-uniform skin distribution) and the flow rate (with turbulence and no turbulence) are investigated. The results obtained from this investigation show significant potential to assist in making practical decisions on the favorable parameters for the success of the field development in terms of equivalent skin factor, flow rate, and inflow performance relationships (IPR).