The study of gas-condensate reservoirs has been a fruitful field of research in the last years because of their peculiar behaviour. Gas cycling is the recovery process of choice for gas-condensate reservoirs but this process can often not be implemented because of economic reasons. Nitrogen is a potential alternative injection gas. Nevertheless, this has also disadvantages. The application of these processes is more complex in the offshore sites. This paper describes laboratory studies performed to evaluate the effectiveness of some gases (CO2, N2, lean natural gas) in displacing condensate from naturally fractured gas-condensate reservoirs (offshore field). Numerous hurdles had to be overcome. The experiments represented the behavior of a reservoir under HP/HT conditions, 334 °F and 8455 psia. The results of CO2 and natural depletion showed little difference in their ability to recover condensate. The natural gas raised the recovery of the light fraction, but, by contrary, the addition of N2 made evident to be less effective than the rest. The residual saturations and condensate recovery were measured and the results are presented. The detailed analyses revealed that natural gas seems to have been more effective in recovering condensate. Under these conditions, condensate recovery will significantly increase if the lean natural gas is injected. The answers are in agreement with the simulation model. The conclusions are relevant to the overall management of gas-condensate reservoir. These experiments will serve as a guideline to develop the long term corporate strategy to improve additional recoveries in Mexico.

Low Salinity Water Injection (LSWI) has received much attention recently as an Enhanced Oil Recovery (EOR) technique. Extensive research programs have been launched to investigate and identify positive effects of LSWI on oil recovery. Experiments have been performed on different formations and crude oils in order to identify the cause of wettability alteration, which is considered as the main reason for the observed additional oil recovery. The majority of the studies reported in the literature have been performed on light oils showing positive results, which represent a significant opportunity for these reservoirs. However, application of LSWI in heavy oils has received much less attention and poses a big challenge, especially in carbonate heavy oil reservoirs.Carbonate reservoirs are generally much more complex than their sandstone counterparts. Further difficulties arise when the reservoir is naturally fractured. These features as well as the oil-wet or mixed-wet conditions that dominate carbonate formations usually result in low recovery factors. The available data suggest that the ultimate recovery factor from these reservoirs is low and in the range of 25 to 45%, depending on the applied method. Although the most widely used method for heavy oil recovery is the thermal processes, non-thermal processes such as gas injection and smart fluids are gaining increasingly more interest amongst operators.In this paper, we present the results of an integrated experimental and simulation study performed in order to explore the potential of using low salinity water as an injection fluid for secondary and tertiary oil recovery from heavy oil carbonate reservoirs. Coreflood experiments were performed to derive measured relative permeability curves. This data were then used to numerically simulate the injection of low salinity water. A systematic sensitivity analysis was then performed to investigate the impact of reservoir parameters on the performance of LSWI in these reservoirs. The parameters considered included: reservoir thickness, well spacing, permeability, heterogeneity, and reservoir pressure. The numerical simulation results confirmed the high potential of LSWI for recovering heavy oils. Oil recoveries of up to 70% (OOIP) were predicted when LSWI was used as secondary recovery, which was consistent with the results from laboratory experiments. On the other hand, high salinity water injection just recovered less than 35%. LSWI as a tertiary recovery method also demonstrated high oil recovery which improves the economics of field applications of waterflooding as less water needs to be injected in the field for achieving the same oil recovery factor when low salinity water is used compared to high salinity water.

For decades, it has been observed that temperature has a significant impact on viscosity reduction, mainly, in heavy and extra-heavy oils where increasing the temperature will improve the flow of oil through the reservoir. Austad and his group have reported that three main ions (SO42−, Mg2+, Ca2+) are potential determining ions for improving oil recovery in carbonate rocks. Both of them must act together. Their studies focused on studying light oils. At the same time, they pointed out the importance of injected fluid/crude oil/rock interactions. Water injection is the most widely used oil recovery technique which has been extensively applied globally in both light and heavy oil reservoirs for decades. Historically, the composition of injection water is dictated by the source of water available for injection. However, recent investigations have shown that the composition of the flood water can have a significant impact on oil recovery achived by water flood. Both total salinity and individual ions content of water have been shown to affect the performance of water flood. It has also been observed that interactions between water and crude oil may affect the oil viscosity. Most of the available research results are on light oil systems but the impact of water composition and its interactions with heavy oil have not been investigated. In this paper, we have experimentally investigated the interactions between brine and heavy oil. The focus of the study was largely on the impact of brine on heavy crude oil viscosity. Four different heavy oil samples were selected from a group of reservoirs and tested in this study. Experiments were conducted using different types of water at different temperatures. Synthetic seawater, formation water, normal brine and distilled water were used as selected brines. The heavy oils were brought in contact with selected brines such that each sample (system) consisted of 80/20 (brine/heavy oil) volume percent. The viscosity and water contact of the each oil was measured before and after the oil had been in contact with brine. The results of this paper indicate the crude oil viscosity may be altered due to contact with brine. The composition of brine as well as crude oil affect whether the oil viscosity increases, decreases or remains unchanged. The results are important for water injection and handling both on the surface and also in the reservoir.

Enhanced Oil Recovery (EOR) from carbonate reservoirs can be a great challenge. Carbonate reservoirs are mostly oil-wet and naturally fractured. For this type of reservoirs, primary production is derived mainly from the high permeability fracture system which means that most of the oil will remain unrecovered in the low permeability matrix blocks after depletion. Further difficulties arise under high pressure and high temperature conditions. Oil recovery from carbonated rocks may be improved by designing the composition and salinity of flood water. The process is sometimes referred to as smart water injection. The improvement of oil recovery by smart water injection is mainly attributed to wettability modification in the presence of certain ions at high temperature. The resultant favourable wettability modification is especially important for naturally fractured reservoirs where the spontaneous imbibition mechanism plays a crucial role in oil recovery. The objective of the work presented here was to experimentally investigate the performance of smart water injection for heavy oil recovery from carbonate rocks under high reservoir temperature. A series of coreflood experiments were performed using a group of carbonate cores in which smart water injection was tested under both secondary and tertiary injection conditions. The experiments were conducted at 92 °C using an extra-heavy oil. Seawater from Gulf of Mexico (GOM) was used in the seawater injection experiments and the smart water used in the tests was obtained by 10 times dilution of the seawater. Although concentration of SO42− is lower in the smart water, the occurrence of SO42− as anhydrite in carbonates may be sufficient to stimulate a similar reaction between the carbonated rock and the injected water with lower salinities at high temperatures. Seawater injection resulted in oil recovery ranging between 30% and 40% whereas smart water injection resulted in 60% oil recovery from the same system. Additionally, analyses of brine composition before and after coreflood experiments confirmed that the effluent concentrations of SO42−, Mg2+ and Ca2+ changed compared to its original values in the injected water. The results indicated that, for some cases, the source of these ions was dissolution from the rock surface. The reactivity of the rock increased when lower salinity water was used.

In the search for oil and gas during the past century, other gases have been encountered. These gases had little or no economic value and areas known to contain them were avoided during drilling.Deposits of CO 2 rich gas (>50 %) are present worldwide but in limited areas -USA, mainly. Few studies of natural CO 2 reservoirs are currently available to determine and analyze its accurate exploitation. CO 2 concentrations ranging between 71 and 98 % have been discovered in the Northeast of Mexico. Preliminary evaluations (SPE-107445) of the available data for Quebrache field indicated potential gas reserves.Complementary analyses to date have shown that on balance, the Quebrache field offers a significant opportunity for developing Enhanced Oil Recovery (EOR) projects. This new study divides the field into tree important areas. This paper presents: a) recent reservoirs discovered b) estimated reserves for all tree areas with CO 2 sources (Central Area, Northern Area and Southern Area), c) efforts made to evaluate its potential d) opportunities to invest in and operate a world-class CO 2 reservoir, etc. The Central Area reveals 2 important reservoirs. These reservoirs are relatively continuous and could produce and drain reserves during long period. Original Gas-In-Place (OGIP) volumes are likely conservative because in its calculation it is assumed a gas-water contact (there is contact apparent in the well logs). The Quebrache field would provide strategic value to CO 2 injection programs. The CO 2 accumulations described in this paper could play a major role in recovering additional oil from fields in the North of Mexico. Thus, CO 2 accumulations in the right place and at the right time may become production targets in the future.