Summary An accurate minimum miscibility pressure (MMP) is one of the key factors in miscible-gasflood design. There is a variety of experimental and analytical methods to determine the MMP, but the most-reliable methods are slimtube experiments, 1D slimtube simulations, mixing-cell models, and the fast key-tie-line approach using the method of characteristics (MOC). Direct comparisons of all these methods generally agree well, but there are cases in which they do not. No explanation has yet been given for these anomalies, although the MMP is critically important to recovery. The focus of this paper is to explain when current MOC results assuming that shocks exist from one key tie line to the next may not be reliable, and how to identify when this is the case. We demonstrate, using fluid characterizations from Middle East oils, that the MMPs using this MOC method can be more than 6,500 psia greater than those calculated using a recently developed mixing-cell method. The observed differences in the MMP increase substantially as the API gravity of the oil decreases, likely the result of the onset of L1-L2-V behavior. We show that the key tie lines determined using this MOC method do not control miscibility for such cases. We explain the reasons for these differences using simplified pseudoternary models and show how to determine when an error exists. We also offer a way to correct the MMP predictions using the MOC for these complex gas/oil displacements without solving for the complete compositional path.

The present work was carried out to investigate the effect of pore s true ture on non-D arcy gas flow to enable a better understanding of the relationship between the inertial coefficient and various rock properties. Measurements of porosity, permeability, inertial coefficient and capillary pressure were made on some 40 core samples, as well as visual observations under optical and scanning microscopes.The results obtained using this integrated approach helped to explain the wide scatter observed in conventional inertial coefficientpermeability correlation plots. It is shown that the inertial effect is not only a function of porosity and permeability, but is also controlled by other factors such as aspect ratio, coordination number, heterogeneities, surface roughness etc.

Gas injection as an EOR method is being considered for the giant Al Shaheen field, located offshore Qatar. The field is characterized by large lateral variations in fluid properties; the oil gravity ranges from 16 to 38 °API and significant variations in initial GOR and saturation pressure are observed.An extensive experimental program aimed at establishing the miscibility behaviour for this complex fluid system has been performed. Experiments included a range of gas injection tests such as swelling and multi-contact miscibility tests, enrichment studies and slimtube measurements. The miscibility behaviour across the range of oil gravities has been very well captured with a single equation of state (EOS) model, as described by Lindeloff et al. (2008).Slimtube measurements are the preferred method for establishing minimum miscibility pressures experimentally as condensing/vaporizing effects can be captured in this setup. The physical dispersion of the slimtube was characterized by a specially designed experiment using first-contact miscible (FCM) fluids. The results of the FCM experiments were used to determine the degree of numerical dispersion required in a 1D slimtube simulation model to match the measured data. An extrapolation towards an infinite number of cells was then performed to estimate the dispersion-free minimum miscibility pressure (MMP) from the slimtube experiments conducted on live reservoir oil using carbon dioxide as injection gas.In addition to the slimtube simulations, several algorithms for estimating the minimum miscibility pressure have been compared; some are empirical correlations, others are based on analytical gas injection theory using the method of characteristics (MOC) limiting tie-line method and the last one relies on a mixing-cell approach. The advantages and drawbacks of each approach are discussed, and the results are compared to laboratory data. In general, there is a very large spread in predicted MMP using carbon dioxide as injection gas. Empirical correlations generally overpredict the MMP for light oils and underestimate the MMP for heavy oils. Various key tie-line methods using the same tuned EOS model provide very different estimates of the MMP and some of them exhibit convergence problems. The results of the present work suggest that the mixing-cell model provides the most robust estimate of MMP over a large range of oil compositions, subject to EOS description. In essence, there is currently no prediction method that can replace the slimtube experiments.

Gas injection as an EOR method is being considered for the giant Al Shaheen field, located offshore Qatar. The field is characterized by large lateral variations in fluid properties across the field. The oil gravity ranges from 16 to 38 °API and significant variations in initial GOR and saturation pressure are observed. The field is developed with horizontal wells with up to 35,000 ft long reservoir sections. The oil gravity may vary considerably along a horizontal well, which needs to be considered when evaluating further field development options involving miscible as well as immiscible gas injection. An extensive experimental program aimed at establishing a model for the miscibility behavior for this complex fluid system is described. The work resulted in the development of an equation of state (EOS) model capturing the miscibility behavior across the range of API gravities, as well as a set of black oil correlations consistent with the EOS. A method for initializing compositional reservoir simulations with the developed EOS based on API, GOR and saturation pressure maps of the field was developed. This methodology allowed a finely discretized compositional variation to be represented in the compositional simulation models giving an accurate and detailed fluid phase behavior description. Introduction The Al Shaheen field is located in Block 5, off-shore Qatar, as seen in Figure 1. The field development started in 1992, details on the field history and layout can be found in the paper by Thomasen et al. [1]. The field is currently producing some 350,000 stb oil/d from two thin separate Cretaceous carbonate formations and an overlying sandstone formation. The field is developed with long horizontal wells placed partly in radial and partly in parallel line drive patterns of alternating water injectors and oil producers. A map of the current and planned well patterns for all reservoirs is seen in Figure 2. The carbonate reservoirs are characterized by relatively thin oil columns with a large areal extent (25 km by 45 km) and fairly low permeable rock, with typical permeabilities in the 1–10 mD range. The PVT properties of the oil exhibit large lateral variations, with API gravities ranging from 16–38 °API within the same reservoir. The field has several gas caps and large variations in solution GOR and saturation pressures. A hypothesis for the origin of the complex fluid variations observed is that the reservoir has been charged by separate oil pulses followed by gas influx and biodegradation. Further development studies are ongoing focusing on expansion of the current water flood scheme as well as EOR. One of the more promising EOR processes considered is Water-Alternating-Gas (WAG) injection using either CO2 or hydrocarbon gas as injection gas. The reservoir simulation work supporting these studies includes both black oil and compositional modeling. The fluid property variations constitute a significant challenge in simulating the field performance, and the present work describes elements of the PVT data acquisition and PVT modeling workflows applied to support the simulation model development.

3D pore-scale imaging and analysis provides an understanding of microscopic displacement processes and potentially a new set of predictive modeling tools for estimating multiphase flow properties of core material. Reconciliation and integration of the data derived from these models requires accurate characterization of the pore-scale distribution of fluids and a more detailed understanding of the role of wettability in oil recovery.The current study reports experimental imaging progress in these endeavors for a preserved-state carbonate core from a Middle Eastern waterflooded reservoir. Micro-CT methods were used in combination with novel fluid X-ray contrasting techniques and image registration to visualize the 3D pore-scale distribution of residual oil in mini-plugs. Segmentation of the registered tomograms and their differences facilitated estimation of the residual oil saturation. These predictions from digital analysis agreed reasonably well with laboratory measurements of oil saturation from extraction of sister mini-plugs and spectrophotometry. The tomogram segmentations provide additional information beyond this average value, such as the fractions of oil associated with macroporosity and microporosity.After the tomogram acquisitions, one of the dried mini-plugs was cut and SEM imaged at this exposed face to provide 2D images of fine features below the micro-CT resolution limit, such as the characteristic dimpled texture of asphaltene films on calcite surfaces due to their local wettability alteration in the reservoir. A new registration procedure was developed to embed the SEM images from the cut plug into the tomogram of the original uncut plug at their correct locations, so that this highresolution wettability information could be integrated into the 3D pore network description and correlated to the local distribution of residual oil.