The low recovery and high oil volume remaining in shale oil reservoirs are a strong motivation to investigate the application of enhanced oil recovery methods in these reservoirs. This paper presents the potential of applying cyclic CO 2 injection to improve the recovery factors of shale oil reservoirs. Cyclic CO 2 injection could be an effective technique to improve the oil recovery of this type of reservoirs for several reasons. It is a single-well process; well-to-well connectivity is not required, the hydraulic and natural fractures provide a large contact area for the injected gas to penetrate and diffuse into the lowpermeability matrix; and the payback period of the cyclic CO 2 injection process is short compared with the other flooding process. Very limited numerical and laboratory studies are available to study the feasibility of CO 2 huff-n-puff for shale oil reservoirs. Latest numerical studies have revealed that CO 2 huff-n-puff technique could be an effective method to increase recovery factors of shale oil reservoirs. In order to support the numerical studies results, a laboratory study was conducted using shale cores from Mancos and Eagle Ford. The aim of this study is to evaluate the potential of cyclic CO 2 injection. Many design parameters such as soaking period, soaking pressure, and numbers of cycles were considered to evaluate the feasibility of cyclic CO 2 injection. The laboratory results indicate that cyclic CO 2 injection improved recovery of shale oil cores from 33% to 85% depending on the shale core type and the other operating parameters. These results have shown that cyclic CO 2 injection is a promising method to improve the recovery of shale oil reservoirs. Also this study aided to develop a better understanding of the performance of cyclic CO 2 in shale oil reservoirs.

Low oil recovery in shale oil reservoirs and vast shale reservoir volumes stimulate our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. A recent numerical study has indicated that cyclic gas injection could be an effective method to increase the oil recovery of shale oil reservoirs, and gas channeling can be mitigated. This paper presents our experimental verification and quantification of the potential to improve oil recovery by cyclic gas injection in shale oil reservoirs. Core plugs of Barnett, Marcos and Eagle Ford shales were used. The oil used was Mineral oil (Soltrol 130) and the gas used was Nitrogen. Unfractured cores were used in the experiments. The effects of cyclic time and injection pressure on oil recovery, among other parameters, were investigated. Our results also showed that cycle gas injection could increase the recovery from 10 to 50% depending on the injection pressure and shale core type. This study shows that one of the important mechanisms of cyclic gas injection is the pressure effect that causes a large pressure drawdown during the production phase. The cyclic gas injection provides an effective and practical method to improve oil recovery in shale reservoirs because the gas needed is available in liquid-rich shale plays.

The CO2 flooding is a proven enhanced oil recovery technique to obtain high oil recovery from complicated formations and can be applied to various types of oil reservoirs. It can be injected as immiscible or miscible flooding but immiscible flooding is less effective than miscible flooding. Two types of miscibility can occur: first contact miscibility and multiple contact miscibility. First contact miscibility happens when a single phase is formed when CO2 is mixed with the crude oil. Multiple contact miscibility occurs when miscible conditions are developed in situ, through composition alteration of the CO2 or crude oil as CO2 moves through the reservoir. The miscible flooding process involves complex phase behavior, which depends on the temperature, pressure and fluid properties of the oil reservoir. The CO2 increases oil recovery by oil swelling, reduction of oil viscosity and density, the acidization of carbonate formations and miscibility effects. Multiple-contact miscibility between the injected CO2 and oil can be achieved at pressures above the minimum miscibility pressure (MMP). MMP is the pressure at which the reservoir fluid develops miscibility with CO2 and is a very important parameter in a well-designed CO2 flood project. Some reservoirs are considered tight because of poor rock or fluid characteristics. The main objective of this study is to investigate the performance of CO2 miscible flooding in tight oil reservoirs. This includes determination of minimum miscibility pressure (MMP) involving carbon dioxide and crude oil and miscible CO2 core flooding. This paper addresses the results of CO2 miscible flooding applied to a known reservoir. Several CO2 miscible flooding experiments were conducted using live oil at reservoir temperature and pressure above the MMP on composite cores of known reservoir. The MMP was determined experimentally using the slim tube. High oil recovery from these experiments indicates that the MMP determined from slim tube studies was correct and such a high recovery is only possible if full miscibility occurs during the displacement. The analytical correlation also gave a MMP consistent with MMP determined from slim tube experiments. Introduction Certain reservoirs have been classified "tight" at the time of their discovery, simply because of poor reservoir characteristics. The exploitation of these reservoirs was judged uneconomical at that time because of their low production rate. In fact, the decision whether to produce or not from a reservoir that has been judged "tight" depends not only on the economical context at the time this decision is taken but also on the state of technology prevalent at the time of this decision. It is natural that any change in the price of oil, or any breakthrough in technology especially in drilling, production engineering and enhanced oil recovery can affect significantly the feasibility of developing these tight reservoirs. Reservoirs that have been judged tight on the basis of thirty year old technology may become economical when modern recovery techniques are applied. Both the economical context and the state of new technologies in the domain of enhanced oil recovery, drilling and production engineering have a significant effect on the feasibility of developing these reservoirs.

Drilling Unayzah-B gas reservoir (shale and sandstone) in Saudi Arabia requires high mud density (± 95 pcf). To formulate this mud, calcium carbonate particles were used, because of their high acid solubility. However, when drilling the 5–7/8 inch hole, sticking occurred, which resulted in expensive fishing and/or sidetrack operations. To minimize these problems, barite was added with CaCO3 to reduce the amount of solids needed to formulate the drill-in fluid. However, barite is acid in-soluble and may cause formation damage. Formate drill-in fluids with low CaCO3 content were used to drill some wells in this reservoir, however these fluids are expensive and corrosive if their high pH values were not maintained in the field. Saudi Aramco has developed drill-in fluids that are based on manganese tetra oxide particles to drill deep gas reservoirs. The properties of these (D50 = 1 micron), spherical shape, and high specific gravity (4.8 g/cm3) make them good weighting material compared to CaCO3 (2.78 g/cm3 and D50 = 10 micron)and BaSO4 (4.25 g/cm3 and D50 = 20 micron). The main objective of this study is to discuss lab work that was performed to design water-based drill-in fluids using KCl/Mn3O4 at 95 pcf. A second objective is to compare the properties of the new fluid with two typical fluids that are currently used to drill Unayzah-B reservoir. The first fluid is KCl/BaSO4/CaCO3 and the second one is potassium formate/ CaCO3. The experimental work included measuring the rheological properties, thermal stability, API and HT/HP filtration of the three drill-in fluids. The results obtained showed that several polymers can be used to design KCl/Mn3O4 -drill-in fluids. The developed fluid had better thermal stability and filtration control compared to the drilling fluids that are currently used. This paper will discuss the results obtained and will demonstrate that the new fluid can save time and cost of drilling deep wells. Introduction Designing of drilling fluids for deep wells is challenging. Therefore, it has been the topic of many research studies. McCaskill and Bradford1 mentioned the factors that we need to consider when designing drill-in fluids. For example, formation permeability determines filtration characteristics. Temperature or water-sensitive formation determines the type of polymer and type of drill-in fluids needed. The authors also suggested that there are goals in designing drill-in fluids that we need to consider such as rheological properties to provide good carrying capacity and minimum filtration control loss. Carico and Bagshaw2 showed how different polymers are used for filtration control, viscosity modification and shale stabilization. There are different types of polymers that can impact the rheological properties and filtration of drilling muds. Some polymers lose viscosity at high temperatures because of their degradation and instability at harsh conditions such as xanthan gum and starch. Some polymers are not effective in salt solutions because salt inhibits hydration of polymers affecting their functions. Polymer compatibility with drill-in fluids is important to achieve good suspension, rheology and filtration control to ensure good hole cleaning and less formation damage. Abrams3 explained how designingdrill-in fluids depends heavily on the selection of a suitable size of weighting materials that will work as bridging materials. Once the solids invade the formation, they cannot be removed by natural flow. Abram stated that "the medium particle size of the bridging material should be equal to or slightly greater than 1/3 the median pore size of the formation." He also suggested using bridging materials at least 5 vol% of solids in the fluid. Ezzat4 showed the requirements for water-based drill-in fluids for horizontal wells such as physical stability, cutting transport, lubricity and formation damage control. The hydrostatic pressure of the drill-in fluids must be high enough to control the formation pressure, but not too high to avoid fracturing the formation and losing circulation. Using bridging materials is important to minimize filtrate invasion, mitigate fines migration and improve hole stability. In deviated wells, cutting accumulation and settling while drill-in fluids are in static motion is a major concern. The drill-in fluids should have good rheological properties to prevent solids and cuttings settling. The author also stressed the importance of conducting core flood testing to evaluate formation damage at reservoir temperature and pressure.

Slimtube measurement is one of the standard experimental techniques used for determining the minimum miscibility pressure (MMP) of an oil and injection gas system prior to the initiation of an enhanced oil recovery (EOR) project. It is preferred because it involves actual fluid displacement in a porous medium. However, the specific criterion for determining the cut-off point during the measurement is not uniquely agreed upon in the literature. Different criteria have been proposed by researchers and this has been one of the setbacks of using Slimtube measurements. The most commonly used criterion is the 1.2 PV criterion, which uses the recovery after injecting 1.2 pore volumes of the displacing gas as the cut-off. However, experimental observations show that even at supercritical condition, the volume of a gas is a strong function of the experimental pressure. Therefore, there is a need to develop an alternative means of determining the MMP that is not subject to particular pore volumes injected during Slimtube measurements. This work presents different means of determining the MMP, based entirely on recovery and the particular displacement phenomenon. In this approach, two new parameters are defined - the instantaneous recovery rate (IRR) and the oil recovery rate (ORR). The maximum values for these parameters for each experiment are used as the cut-off value. This new criteria was used in analyzing nine experimental data using oil from the Permian Basin. The results were compared with MMP prediction based on maximum recovery from each of the runs and the results were found to be in agreement. These new criteria will provide consistent cut-off point for experimental runs because Slimtube measurements take a long time to complete. The new procedure ensures that adequate data have been gathered during each experimental run, sufficient for a consistent experimental analysis.