The purpose of this paper is to investigate the effects of phase behavior on the sequestration CO2 of in depleted gas reservoirs (dry gas, wet gas and retrograde gas). Carbon dioxide sequestration in depleted and abandoned gas reservoirs can accomplish two important objectives. Firstly, it could be important part of present climate control initiative to reduce the concentration of carbon dioxide in the atmosphere. Secondly, it could be instrumental to enhance gas and condensate recovery. Using the pressure-temperature diagrams and two phase flash calculations, the phase behavior of natural gas-carbon dioxide mixtures were analyzed to provide enlightenment on the sequestration process. From analysis of simulated results, it was found that carbon dioxide exhibited a drying effect on wet and retrograde gas mixtures and a wetting effect on dry gas. The results for retrograde gas condensate depended on the composition of reservoir fluids at abandonment conditions. The main difference being the liquid volume present with increasing pressure and carbon dioxide concentration. This influenced the volume of condensate vaporized with addition of carbon dioxide. It was also determined that carbon dioxide lowers the compressibility factor of all gas types. These results are favorable for carbon dioxide sequestration because decreasing compressibility factors represents increasing storage capacity. Introduction In the year 2000, the fossil fuel combustion in the U.S. accounted for the release of approximately 114.1 trillion cubic feet1 of carbon dioxide (CO2) to the atmosphere. The volume of carbon dioxide emitted has increased steadily since the industrial era leading to concerns of global warming and the ensuing climatic changes. Sequestration of carbon dioxide in depleted gas reservoirs, with storage capacity estimated to be 140 GtC (Gigatonnes Carbon) worldwide,2 is considered as a possible solution. Problem Description The sequestration of carbon dioxide in depleted gas reservoirs results in contact and eventual mixing between carbon dioxide and natural gas. Early in the sequestration process, portions of the reservoir contain pure natural gas, mixtures of natural gas and carbon dioxide, and pure carbon dioxide. Eventually the entire reservoir becomes a homogeneous mixture of the two fluids. Before there is complete mixing of natural gas and injected carbon dioxide within the reservoir, there is variation of carbon dioxide concentration in the reservoir. Analyzing the phase behavior of sequestration aids in understanding how the properties of natural gas vary with carbon dioxide concentration of a homogeneous mixture and can be extended for known compositional gradients. In planning geologic sequestration projects of depleted gas reservoirs, it is important to know how natural gas behaves under reservoir conditions when carbon dioxide is injected into the reservoir. In particular, the compressibility factor (Zfactor) of the gas phase and the amount of liquid present at reservoir and surface conditions are particularly useful in predicting phase behavior, enhanced gas and condensate recovery. Predictions and analysis of the phase behavior of carbon dioxide-natural gas mixtures in depleted gas reservoirs, account for the physical characteristics of the in situ natural gas, the injected gas at reservoir conditions, and the consequent gas mixture. Phase behavior of the fluids involved in sequestration is investigated as a function of pressure, temperature and gas composition. By this means it is possible to give a more accurate estimate of the volume of sequestered carbon dioxide, enhanced gas production and enhanced condensate production that can be sequestered in a particular reservoir. This is a crucial guideline in sequestration development schemes when considering enhanced gas and condensate recovery. By using this approach, assessing a depleted gas reservoir as a candidate for carbon dioxide sequestration based on temperature, pressure and gas type is necessary.

We developed an injection strategy to recover moderately heavy oil and store carbon dioxide (CO 2 ) simultaneously. Our compositional simulations are founded on pressure/volume/temperature-(PVT-) matched properties of oil found in an unconsolidated deltaic sandstone deposit in the Gulf of Paria, offshore Trinidad. In this region, oil density ranges between 940 and 1010 kg/m 3 (9 to 18 API). We use countercurrent injection of gas and water to improve reservoir sweep and trap CO 2 simultaneously; water is injected in the upper portion of the reservoir, and gas is injected in the lower portion. The two water-injection rates investigated, 100 and 200 m 3 /d, correspond to the water-gravity numbers 6.3 to 3.1 for our reservoir properties. We applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals in a simplified representation of the unconsolidated Forest sand found offshore Trinidad. Twelve simulation runs were conducted, varying injection-gas composition for miscible-and immiscible-gas drives, water-injection rate, and injection-well orientation. Our results show that water-over-gas injection can realize oil recoveries ranging from 17 to 30%. In each instance, more than 50% of injected CO 2 remained in the reservoir, with less than 15% of the retained CO 2 in the mobile phase.

We study the design of enhanced oil recovery in heavy oil reservoirs combined with CO2 storage using field-scale reservoir simulation. We consider properties typical of fields offshore Trinidad and Tobago with oils whose density ranges between 940 and 1010 kg/m3 (9-18 degrees API). We first tune a three-parameter Peng-Robinson equation of state to match measured PVT data. We use experimental design to study the influence of oil properties, phase behavior and injection design on oil recovery and net CO2 storage. Carbon dioxide injection into heavy oil reservoirs enhances oil recovery through the mechanisms of crude viscosity reduction, oil swelling and immiscible gas drive. The process involves significant recycling of the injected CO2, but the reservoir is managed to keep as much of the injected CO2 as possible underground.

We have developed an injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. Our compositional simulations are based on PVT-matched properties of oil found in an unconsolidated deltaic, sandstone deposit in the Gulf of Paria, offshore Trinidad. In this region oil density ranges between 940 and 1 010 kg/m3 (9-18 degrees API). We use counter-current injection of gas and water to improve reservoir sweep and trap CO2 simultaneously; water is injected in the upper portion of the reservoir and gas is injected in the lower portion. The two water injection rates investigated, 100 and 200m3/d, correspond to water gravity numbers 6.3 to 3.1 for our reservoir properties. We have applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals. Eight simulation runs were conducted varying injection gas composition for miscible and immiscible gas drives, water injection rate and injection well orientation. Our results show that water over gas injection can realize oil recoveries ranging from 17 to 30%. In each instance more than 50% of injected CO2 remained in the reservoir with less than 15% of that retained CO2 in the mobile phase.

Although Trinidad and Tobago has an abundant supply of relatively pure CO2 and more than 1 billion barrels of heavy oil deposits there are no active enhanced oil recovery (EOR) projects using carbon dioxide (CO2). In this paper, we have performed black oil simulation studies to evaluate several injection strategies with carbonated water, varying the salinity and viscosity of injected water. The salinity was varied by 1,000 and 35,000 ppm. The viscosity was increased by adding 0.1 weight percent polymer to injected water. The investigation was carried out using a commercial reservoir simulator. The simulation grid represents the properties of a quarter five-spot of the Lower Forest sand of the Forest Reserve Field. The reservoir simulation components used are water, polymer, H, Na, Cl-, dead oil, solution gas and CO2. The Stone #1 three-phase relative permeability model was used to calculate the three-phase relative permeabilities from two-phase data. In addition, a factorial experimental design was utilized and twelve simulation runs were done along with nine benchmark runs for comparison to other EOR methods. From the results obtained the following was concluded: water salinity has no effect on either oil recovery or carbon dioxide storage; polymer injection increases oil recovery and carbon dioxide storage. We found the optimal injection strategy to be a cycling of carbonated water alternating with polymer injection.