The paper examines the sensitivity of reservoir simulations to uncertainties in viscosity. The simulations are performed for three different oils, ranging from light to viscous, for three different geological terrains. In each case, the viscosity has been estimated by a number of currently recommended prediction methods and by recourse to the measured values. The preliminary results indicate that the results of reservoir simulations are sensitive to the fluid viscosity. The sensitivity increases with increase in the absolute viscosity of the oil, increase in heterogeneity of the reservoir and increase in uncertainty in viscosity. The results show, that in the worst case scenario examined (e.g. heavy, viscous oils, ? > 6 cp) a ±1% error in viscosity will produce a 1% error in the cumulative production. Overall, the preliminary results indicate that the common assumption in reservoir simulations, that the accuracy of fluid properties has a marginal influence on the reservoir performance, is false. Uncertainties in viscosity can lead to large errors in predicted production rates, thus unduly influencing the economics of reservoir exploitation. Introduction For effective and efficient exploitation of oil fields, good reservoir characterisation is paramount; thus requiring an adequate understanding of rock and fluid properties. It has been petroleum industry practice to assume that fluid properties are well characterized and that all the uncertainty associated with numerical reservoir simulation is only related to uncertainty in the spatial distribution of rock properties. The present paper examines this preconception by analyzing the sensitivity of reservoir simulations to uncertainties in viscosity. Traditionally, viscosity values required in compositional simulators are either obtained by measuring lab-samples or by one of the available prediction methods. In principle, an accurate measurement of the fluid viscosity, to better than ±1%, can be obtained in a well-characterized experimental apparatus (e.g. primary instruments), with a well-defined uncertainty level, which cannot be demonstrated to be inconsistent with other data or with theory1. Although such instruments do exist 1 their use requires knowledge of a full, fluid mechanics, working equation and requires a number of corrections to be applied to the experimental data, making the analysis expensive and time-consuming and thus, these instruments are not suitable for routine analysis. The instruments currently used in the oil industry do not fulfill any of the requirements of a primary instrument, neither in the design nor in the operation, and consequently their accuracy is much lower. A comparative experimental study2, by five different laboratories, of an identical oil sample showed a spread in viscosity data of the order of ±20%. There is no reason to expect that the accuracy of the routine viscosity measurements, carried out in a standard petroleum sample characterisation, would normally be better than the results of this case.

This paper presents the results of a numerical simulation study aimed at evaluating the effect of rock anisotropy on water invasion and oil bypassing in edge-water-drive reservoirs. A complete set of dimensionless groups for 3D immiscible displacement of oil by water in an anisotropic reservoir is selected using inspectional analysis. The dimensionless groups are validated using numerical simulation. Numerical simulation and statistical analysis are also used to evaluate the effect of each group on water invasion.The results show that the end-point mobility ratio (i.e., mobility contrast for oil and water) has the strongest effect on water invasion, followed by the aspect ratios, the dip angle group and the buoyancy number. Also, it has been found out that rock anisotropy controls the geometry of displacement, resulting in water underruning or overriding the oil, which in some cases may lead to substantial bypassing of the oil reserves.

Field A is a significant contributor within the Kaombo development project, offshore Angola. The field comprises five stacked sedimentary units (A1 through A5, from top to bottom) requiring openhole gravel packs (OHGP) as the sand control technique, and a commingle strategy was key to reducing well count. Production from reservoir A4 could not be commingled with that from other sedimentary layers due to the risk of asphaltene precipitation, and A3, water bearing in one panel, also required isolation. The openhole mechanical packer (OHMP) with OHGP completion was used in field A to reduce the well count from the originally planned eight oil producers (OP) to six OP; this brought savings in excess of USD 100 million. Well 1 in field A penetrates all five reservoirs; it was successfully completed in December 2016 with two OHMPs isolating reservoir A4. A well in field B was successfully completed in May 2017 with one OHMP to allow future water shutoff (WSO) with potential production acceleration as well as estimated ultimate recovery (EUR) increase of more than one million barrel of oil equivalent (MMboe). Downhole gauge data analysis combined with mass balance indicated that 100% pack efficiency was achieved in both wells with the expected packing sequence in the presence of packers bypassed with shunt tubes. The OHMP enhances the versatility of OHGP completions with eccentric shunt-tube screen assemblies, which enable applications such as selectivity, zonal isolation, and water shutoff. The robustness of OHGP completions together with the features mentioned earlier will improve the economics for future projects by reducing capital expenditure (capex) and increasing reserves recovery per well. This application was an important contributor to reduce drilling expenditure (drillex) for the Kaombo development project.

Efficient management of oil reserves involves an understanding of the mechanisms that control the bypassing of oil in water drive reservoirs. The existing analytical models of water front advancement in side-water reservoirs do not account for the combined effects of water underruning and coning. This paper gives correlations for the prediction of the amount of bypassed oil in side-water systems. The correlations have been developed using numerical simulation and an experimental design framework. Considered in the correlations are the effects of dip angle, vertical- to-horizontal permeability ratio, oil viscosity, production rate, oil density, and well penetration. Introduction Displacement of oil by water in side-water systems is controlled by viscous forces, gravity forces, capillary forces, and heterogeneities. These mechanisms or forces may interact with each other during the displacement, originating the formation of multiple fingers, water channeling, and/or gravity underrunning (formation of a water tongue). For low flow velocities, gravity forces tend to dominate the displacement and a stable (constant slope) interface occurs(1). A stable front is desirable because it results in high recovery factors. However, the required flow velocity may be so low that the corresponding critical production rate would not be economical. Generally, production rates needed for economical recovery exceed the critical rates. Therefore, the front becomes unstable and a (gravity) water tongue develops along the bottom of the dipping structure, causing early water breakthrough and oil bypassing. In fact, simulation studies have shown that up to 69% of the oil could be bypassed in side-water systems with unfavourable mobility ratios(1, 2). Also, most of the well's production life is plagued by very high water cut. Knowledge of the motion of the oil-water interface is needed in reservoir engineering in order to determine the amount of oil that will be recovered by the end of the well's operation. The most well known analytical models for the determination of the motion of the oil-water interface are the models presented by Richarson and Blackwell(3), Dake(4), Dietz(5), Outmans(6), and Sheldon and Fayers(7). Potential use of these models for predicting a well's recovery is important due to the simplicity of calculations as compared to reservoir simulations, which become quite complex in modelling individual wells. Recently, the analytical models were verified for stable and unstable cases(1). The results indicated that Dake and Dietz are the best models because of their accuracy and ease of use(1). Despite convenience, analytical models are poor estimators of the water breakthrough time(1). Moreover, Dake's and Dietz's models are based on assumptions that may not represent the real physics of the displacement of oil by water in dipping structures. For example, the models assume isotropic reservoirs. They also assume completely segregated flow, i.e., consider the thickness of the capillary transition zone negligibly smaller than the thickness of the pay zone. In addition, these analytical models are two-dimensional, so they ignore the physical size of a well at the producing end of the dipping structure.