This describes the results of extensive phase behavior and slim-tube analyses for CO2 EOR study in a Middle Eastern offshore reservoir. The objectives of this study are to evaluate the effectiveness of CO2 injection to the target reservoir and to reduce uncertainties based on laboratory and simulation studies. This study is focused on solubility and slim-tube tests in the laboratory studies, and its analyses using an equation of state (EOS) model that reproduces the majority of conventional PVT and solubility swelling results for an associated hydrocarbon gas and oil system. We performed conventional PVT and solubility swelling tests for a CO2-Oil system successfully. With the results of solubility tests, an EOS model was established and tuned for predicting the solubility behavior in the mixing fluid between CO2 and the target reservoir oil within sufficiently acceptable ranges. In addition, we conducted a series of slim-tube tests with CO2 and a synthetic hydrocarbon gas, which is similar compositions to the associated hydrocarbon gas, at some pressure levels. In comparison between CO2 and the synthetic hydrocarbon gas injection, there is a significant difference of oil recovery at relatively low pressure, indicating that CO2 injection is more effective than the synthetic hydrocarbon gas injection. Results of slim-tube tests with CO2 show that the oil recovery reaches greater than 90% at any pressure level, but the displacements of oil at the outlet of slim-tube by the visual cell observations appear in different manners. We simulated slim-tube tests with the adequate EOS model for CO2 injection under carefully arranged simulation conditions. As a result, we confirmed that simulated gas saturation and k-value profiles are consistent with the visual cell observations, and this displacement of oil by CO2 is characterized as condensing/vaporizing drive. These results confirm the effectiveness of CO2 injection to the target reservoir and lessen the uncertainties of fluid interaction at the laboratory scale.

An extensive CO2 EOR study was done for one of a super giant oil field reservoir in offshore Abu Dhabi. This study aimed to evaluate the effectiveness of CO2 injection to the target reservoir and to address uncertainties based on laboratory and simulation studies. This paper is focused on the risk analysis of the asphaltene deposition in CO2 injection based on the laboratory data. In this risk analysis, it is important to distinguish between asphaltene precipitation and deposition. It is believed that precipitation is a necessary but not a sufficient condition for deposition. In some cases, asphaltenes become unstable and form a separate asphaltene rich phase, but they do not deposit. Measurements of asphaltene particle size provide more understanding on the flocculation and deposition mechanisms and allow us to do the risk analysis of asphaltene deposition in CO2 injection. Pressurized oil samples were taken from the target oil reservoir. Laser Light Detection (LLD) and High Pressure Microscope (HPM) systems were utilized to measure asphaltene onset pressure and its aggregation process with injection of CO2. Asphaltene particle size analysis from HPM observations showed the growth of the asphaltene particles. Along with these analyses, CO2 injection core flooding tests were also conducted with this reservoir fluid and this reservoir rock. No symptoms of permeability reduction were observed through the experiments. The overall conclusion of the study for the target reservoir revealed that the potential risk associated with asphaltene problems during CO2 gas injection was relatively low. In this study, 1) this laboratory study indicated the risk of asphaltene deposition by CO2 injection was relatively low in the target reservoir, 2) combination of the experiments revealed an asphaltene precipitation and deposition mechanism, and 3) this systematic approach was established to assess the asphaltene deposition risk.

It is important to predict the amount of bypassed oil in EOR gasflooding since some portion of the flooded domain may be uncontacted by the injected gas due to reservoir heterogeneities residing in various scales. In this paper, we present a new method of deriving immobile and non-vaporizing residual oil saturation under miscible flood (Sorm, Hiraiwa and Suzuki 2007) from the results of CO2 coreflood experiments. We also demonstrate that Sorm is a sort of upscaled parameters able to absorb complex heterogeneous features in the finer scale. We history-matched CO2 coreflood experiments using the two different simulation models: one-dimensional (1D) homogeneous model with Sorm and two-dimensional (2D) heterogeneous model without Sorm. Both of these two models replicated secondary- and tertiary-mode CO2 coreflood experiments using core and fluid samples acquired in one of the Abu Dhabi's offshore fields. Hence we successfully obtained the Sorm based on the coreflood experiments for further use in evaluating CO2 injection in a real reservoir. In addition, we effectively modeled the core-scale heterogeneity using the X-ray computerized tomography (CT) data and pore size distribution (PSD) data derived from mercury injection capillary pressure (MICP) tests in the 2D model.

The results of special core analyses using carbonate rocks from a Middle Eastern offshore reservoir are presented based on laboratory and simulation studies. The study aims to obtain reliable relative permeability in an oil-water system under steady-state conditions, and confirm the resulting relative permeability through a simulation study by comparing water saturation distributions along the core at various injection ratios of water to oil. The difficulties in steady-state relative permeability measurements are to determine water saturations and steady-state conditions as only the effluents are measured. To obtain accurate water saturations, we adopted an X-ray CT (Computed Tomography) scanner that allows us to precisely measure porosity and fluid saturation distributions inside cores under reservoir conditions, especially for reservoir wettability. In addition, not only the ratios of water to oil in effluents but also water saturation distributions derived from CT measurements inside the core were used as a measure of steady-state conditions. Core flood experiments were conducted with periodic measurements at various injection ratios of water to oil. As a result, we obtained eleven relative permeability points with respect to water saturation calculated from CT numbers. Next, a simulation study was conducted to confirm the relative permeability curves using a core model where CT derived porosity and absolute permeability were assigned based on the core flooding experiments. Results of the core flood simulations with the resulting relative permeability curves show that the simulated water saturation distributions are in excellent agreement with those of the core flood experiments, especially low injection ratios of water to oil. Through laboratory and simulation work, it is confirmed that reliable relative permeability measurements were made by carefully determining water saturations and steady-state conditions with simultaneously measuring the effluents from the core and monitoring the inside core by X-ray CT scanner.

Layer IIB is one of undeveloped layers in an offshore Abu Dhabi. The reservoir has large gas cap with saturated oil rim. Low permeability is the main problem in this layer(less than 10 md). In addition, discontinuity in reservoir leads to scatter discontented oil pools all over the layer. Layer IIB is a thin layer with thickness varies from 10 to 30 feet lead to limit the production area. Lithology is dominated by almost dolomite with no secondary porosity. It was noticed that top Layer IIB is always had better geological properties in terms of porosity & permeability than the rest layer. Many trials were unsuccessful in the past to produce from this layer by using slanted wells and Bull heading stimulation. The objective from this well is to collect dynamic data to be used in the development plan since the old trials were failed to produce due to tightness of the reservoir. Therefore, propose was made to drill horizontal well with maximum reservoir contact in the thin good part of the reservoir. Top technology was used in Geosteering to insure horizontal section in the good reservoir part. Coil tubing stimulation with diverter was implemented in the open hole horizontal section to distribute the acid in the hole. For the first time, strong acid (with HCL 25%) was used to improve the productivity of the tight rocks around the well. The well was test and produce at rate of 2.5 MBOPD with reasonable GOR and no water cut. The same completion strategy will be used for the upcoming wells in this layer.