Some surface-active chemicals are able to improve the spontaneous imbibition of water into oil-wet carbonates. In this work, the oil recovery from oil-wet reservoir cores was compared using aqueous solutions of an ethoxylated alcohol (EA) and a cationic surfactant (C12TAB). The experiments were conducted at room temperature using short (∼5 cm) and long (∼30 cm) cores with initial water saturation in the range of 17-33%. Due to wide variation in porous structure, the cores were characterized into two groups, i.e., moldic and sucrosic. The former cores had more than 25% of the pore volume (PV) related to vugs, and the latter appeared more homogeneous. The permeability of the moldic and sucrosic cores varied between 20 and 180 and 80-350 mD, respectively. In general, the efficiency of C12TAB was superior to EA regarding spontaneous oil expulsion from the cores. For the short core experiments, about 40-45% of original oil in place (OOIP) was recovered using C12TAB, while only 10% was the average recovery using EA. The available data for the short cores gave no reasons to discriminate between moldic and sucrosic cores regarding oil expulsion. The long 162 mD sucrosic core expelled 65% of OOIP in the presence of C12TAB. The high oil recovery, compared to the short cores, was related to greater impact of gravity forces. The imbibition of EA solution into the long 45 mD core was very small, less than 5%, but large improvements were achieved when changing to C12TAB solution. Contact angle measurements on oil-wet calcite crystals confirmed that C12TAB was much more effective than EA in altering wettability toward more water-wet conditions.

This paper introduces a new permeability estimation method using the equivalent rock element model which consists of two pore components, one parallel and the other perpendicular to the potential gradient. Both formation resistivity factor and permeability are related to porosity and pore structure, but permeability also depends on pore scale and internal specific pore area. In water wet rocks, irreducible water saturation is a parameter closely related to pore size or scale and internal specific area. Irreducible water occupies space in both parallel and perpendicular pore components and hinders fluid passage. The relative volume occupied in each component varies with many factors such as pore scale and interconnection, fluid properties, mineralogy and wetting characteristics of the mineral/fluid system. This non-uniform occupancy is approximated by a simple power function. An efficient flow porosity is defined by modifying efficient electrical porosity using irreducible water saturation to account for scale and specific pore area. The correlation between efficient flow porosity and permeability is much greater than those in many of the commonly used methods. This method has been applied to several sets of cores from different parts of the world. Better correlations between measured and estimated permeability have been obtained in all datasets compared with other published approaches, such as porosity versus logarithm of permeability, Kozeny-Carman, Wyllie-Rose, and Timur methods. Introduction Permeability is one of the most critical reservoir properties and is probably one of the most difficult to accurately obtain for reservoir description. Permeability can be directly measured in core analysis or computed from well tests. Core analysis measures properties on a scale of centimeters. Well tests cover an area orders of magnitude larger, but its vertical resolution is much lower than desired. A possible linkage between core and well test analyses is to estimate permeability from properties measurable by well logs. For decades, many efforts have been made to estimate permeability using indirect measurements. Some follow statistical approaches1,2 such as neural networks to find correlations between permeability and various measurements. Others attempt to relate permeability with different properties through a physical model.3 These two approaches are sometimes integrated.4,5 Kozeny6 and Carman7 related permeability with porosity and surface area of grains exposed to fluid flow. They proposed a simple relationship that states permeability is directly proportional to the cube of porosity and inversely proportional to the square of pore surface area per unit volume of rock. For randomly packed spheres, permeability is estimated as:Equation 1 where k is permeability; f is porosity; and Ag is surface area of grains exposed to fluid flow per unit volume of solid material. The specific surface area is difficult to measure directly by conventional methods and is often determined from core sample analysis. Mavko and Nur8 suggested that Kozeny-Carman equation needs to be modified for porosity below percolation threshold. Wyllie and Rose9 proposed a modification to the Carman-Kozeny equation and substituted irreducible water saturation for specific surface area. They conjectured that grain surface area is approximately related to irreducible water saturation, Swir. Their work could be expressed as:Equation 2 where B is a coefficient related to hydrocarbon type and gravity; B' is a correction factor for data fitting. A more generalized Wyllie-Rose relationship is sometimes written as:Equation 3 where P, Q, and R are tuning parameters to be calibrated from the fit to core measurements.

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CO2 flooding has become the fastest growing gas injection EOR method, contributing 4.8% of U.S. oil production. An integrated approach was undertaken to evaluate the CO2-EOR feasibility for Marathon's Rocky Mountain (RM) region assets. The RM assets of the Wind River and Big Horn basins were evaluated using detailed geological and compositional reservoir models imposed with multiple development scenarios. The fractured nature of the RM assets posed a challenge for reservoir modeling, which prompted combinations of approaches such as production ranking to facilitate fracture descriptions. Extensive laboratory CO2-oil PVT tests were also conducted to tune a representative equation-of-state fluid model to confidently quantify reservoir fluid behavior. CO2 injection scenarios for two oil fields were evaluated using compositional dual-porosity and dual-permeability reservoir models. Performance evaluation under multiple sensitivities, namely WAG ratio, fluid properties, injection pressures, and fracture characteristics were also investigated to quantify their impact on oil recovery factors. The simulation recovery results were non-dimensionalized to generate distinct type-curves, which were then applied to areas that have similar fracture and geological characteristics. The unique workflows generated during this study were verified and benchmarked by using them to history match the performance of an analogous RM field currently under CO2 injection. This paper describes the integrated approaches applied to maturing RM assets, which in addition to identifying significant IOR potential, have helped enhance the reservoir's characterizations, standardize subsurface workflows, aid facilities design, and scale-up performance data for optimal reservoir management. 1. Improved Oil Recovery In 1978, the United States Congress commissioned the Office of Technology (OTA)(1) to evaluate the state of the art in U.S. oil production. The OTA concluded that the 300 billion barrels of known U.S. oil were economically unproducible by conventional methods in practice at that time. The OTA report also evaluated a range of enhanced oil recovery (EOR) techniques and their potential for improving the prospects of extracting a sizeable fraction of this known resource base. These major political and administrative amendments triggered increased interest in EOR in late 70's and early 80's, most notably in California and the Permian Basin of West Texas. Now, 30 years later, there is again a strong interest in improving domestic oil production(2), which has been on a continuous decline of approximately 3% per year (Figure 1)(3), while the total 'unproducible oil' referred to in the OTA report(1) has increased to a whopping 400 billion barrels(4). The U.S. Geological survey reported(5) that the bulk of the conventional oil yet to be produced in the world resides in already discovered reservoirs, with the ever decreasing possibility of finding newer reserves. The most important conclusion of this report, from an oil self-reliance point of view, is that the EOR techniques have not been tried for most of these reservoirs. Therefore, the potential for EOR applications in the U.S. is very large with a target of approximately 400 billion barrels(6).