Summary At temperatures above 150 degrees C water dissolution in crude oil becomes significant. Water solubilities in heavy crudes am about 40 mole percent at 250degrees C. Dissolved water acts as a low viscosity solvent reducing the oilphase viscosity. This phenomenon has been considered in thermal recovery simulations but has never been substance in this work the effect of water on viscosity was measured for four crude samples with API gravities ranging from14.2 to 5.3. At the highest experimental temperature of 286 degrees Cviscosities of water saturated samples were about one half of the water-free counterparts. The viscosity reduction, although quite significant, was not as pronounced as the drop estimated by viscosity miles used for hydrocarbon systems. While a log mixing rule or a 1/4 power mixing rule overestimated the viscosity effects, a mole fraction weighted average of the oil and water viscosities was found to match the experimental data. One possible explanation for the failure of the log mixing rule is that the water dissolved in the oil exists not as monomers but as hydrogen bonded dusters. When the mole fraction of water clusters, calculated from a statistical mechanics based theory, isused in the log mixing rule, we find good agreement with experiment. SUMMARY AND CONCLUSIONS At temperatures above 150 degrees C water dissolution in crude oils become significant. Water solubilities in heavy crudes are about 40 mole percent at250 degrees C. Dissolved water acts as a low viscosity solvent reducing the oil phase viscosity. This phenomenon has been considered in thermal recovery simulations but has never been substantiated. In this work the effect of water on viscosity was measured for two heavy oils, Huntington Beach (API gravity = 14.2) and Cloalinga Etchegoin (APIgravity = 10.5), and two tars, West Cat Canyon (API gravity = 5.3) and PeaceRiver (API gravity 6.7). At the highest experimental temperature of 286 degrees C viscosities of water-saturated samples were about one half of the water-free counterparts. The viscosity reduction, although quite significant, is not as pronounced as the drop estimated by viscosity mixing rules used in simulation work in the past. A mole-fraction weighted average of the oil and water viscosity was found to match the experimental data. Dissolved water exists on average as hydrogen bonded clusters. The log mixing rule matches the experimental data when the mole fraction of water clusters is used. Introduction Water dissolution in an oleic phase has been reported. The effect is negligible in crude oils at temperatures below 150 degrees C and becomes very pronounced (more than 60% mole fraction) as the temperature riser, above 280degrees C. The effect of dissolved water on the oleic phase viscosity has never been reported. Its potential impact has been estimated based on viscosity mixing rules typically used in hydrocarbon systems which predict very significant viscosity reductions due to water dissolution at high temperature. These predictions lack experimental support, however.

Summary A well equipped with intelligent components is considered "smart" only when it maximizes its value over the life of the project. The definition of the adequate level of intelligence is the outcome of a multidisciplinary discussion that focuses on the well and reservoir management. To effectively realize the value associated with these technologies, Shell set up a Global Implementation Smart Wells Team at its E&P Technical Center. Jointly with asset teams from around the world, it has reviewed more than 80 projects over the last 3 years. The main result of this work is a faster and more-meaningful implementation effectively realizing the value associated with these technologies. An important byproduct of this work is a list of identified well and reservoir opportunities in which smart completions can add significant value. This paper reviews these opportunities and provides selected examples. Introduction Smart wells include a battery of completion equipment designed to do the following:• Monitor well operating conditions downhole (e.g., flow, pressure, temperature, phase composition, and water pH).• Image the distribution of reservoir attributes away from the well (e.g., resistivity and acoustic impedance).• Control the inflow and outflow rates of segregated segments of the well. Combined with quality readings at surface of total rates and other nonwell mapping technologies, such as time-lapse seismic, smart wells also provide the tools to manage wells, identify undrained oil, and make informed decisions that optimize hydrocarbon recovery.1 The perceived added value associated with these technologies, their complexity, and the need to satisfy reliability demands have driven service companies and field operators to devote staff and resources to develop new and improved products and to explore opportunities to deploy these well-completion components worldwide. Numerous papers and technical literature dealing with field applications and completion specifications can be found elsewhere.2–10 This paper focuses instead on the reservoir opportunities in which the added value can be readily identified. As our industry struggles to improve ultimate recovery and to make marginal projects feasible, wells must provide cost-effective means to gather reservoir information and produce them efficiently. Intelligent completions will become a standard practice in years to come. Currently, that vision is slowly being realized, one well at a time.

The production of oil from horizontal wells in thin rims sandwiched between gas and water is notorious for coning problems. There is a strong tendency for early gas or water breakthrough at the heel, especially if the pressure drop over the length of the well is in the same range as the drawdown. We present two conceptual solutions to counteract the negative effect of well bore pressure drop through the application of downhole measurement and control. One solution concerns inflow switching in a segmented well bore and allows for coning control after breakthrough has occurred. The other solution aims at preventing breakthrough as long as possible. This is achieved by flattening the drawdown profile along the well through controlling inflow at one or more points in an extended stinger. The feasibility of the solutions was demonstrated through numerical simulations over a range of reservoir and well bore parameters. Implementation would require further development of downhole water and gas detection capabilities. Introduction Thin oil rims are relatively thin oil columns, in the order of a few to tens of meters thick, sandwiched between water and gas layers. They often occur in reservoirs with lightly compacted sands having high porosities and high permeabilities of up to several Darcy, and they commonly contain light oils. These properties culminate in favorable reservoir flow conditions, reflected in a low drawdown required for production. However, these properties can also cause production problems, in particular water or gas coning leading to early water or gas breakthrough. Horizontal wells are an attractive solution to reduce the potential for coning because they require lower drawdown than vertical wells for the same production rates. However, a possible problem of horizontal wells is the pressure drop over the well bore caused by friction forces between the fluid and the well bore (Fig. 1). As a result the drawdown at the heel of the well becomes higher than the drawdown at the toe, which increases the tendency for water and gas coning at the heel and thus partially cancels the beneficial effect of the horizontal well. The reduced draw down near the toe of the well also lowers the effectiveness of increasing the well length. Pressure drop over horizontal oil wells has been modeled to various degrees of sophistication1–3. These studies show that, roughly speaking, well bore pressure drop over a horizontal well becomes a problem when it is in the same order of magnitude as the drawdown at the heel. The ratio between pressure drop and drawdown increases for reducing well diameter, increasing well length, and, importantly for many oil rims, increasing reservoir permeability and reducing oil viscosity. Stinger completions Passive stinger completion One of the solutions to the non-uniform drawdown problem is the use of an ‘extended stinger’ to shift the tubing inflow point from the heel of the well to somewhere near the middle4,5. This effectively replaces the horizontal well by two shorter ones (Fig. 2). However, such a ‘passive’ stinger has a number of practical disadvantages:Its dimensions are based on a fixed inflow profile along the well. However, the inflow profile may change over the life of the well due to reservoir pressure transients and due to the breakthrough of gas or water.It requires that the inflow profile along the well bore is known at the design stage. This is usually quite unrealistic because of unpredictable reservoir heterogeneities, in particular near-well bore permeability fluctuations. Passive stinger completion One of the solutions to the non-uniform drawdown problem is the use of an ‘extended stinger’ to shift the tubing inflow point from the heel of the well to somewhere near the middle4,5. This effectively replaces the horizontal well by two shorter ones (Fig. 2). However, such a ‘passive’ stinger has a number of practical disadvantages:Its dimensions are based on a fixed inflow profile along the well. However, the inflow profile may change over the life of the well due to reservoir pressure transients and due to the breakthrough of gas or water.It requires that the inflow profile along the well bore is known at the design stage. This is usually quite unrealistic because of unpredictable reservoir heterogeneities, in particular near-well bore permeability fluctuations.

The presence of a high temperature (>Tg) relaxation in amorphous polystyrene has been investigated further. In the previous work,1 the techniques of differential thermal analysis (DTA) and torsional braid analysis (TBA) were employed to study polystyrene as a function of “monodisperse” molecular weight. The occurrence of the Tll transition appeared to be associated with the attainment of a critical viscosity level with also corresponded with a free volume level. An entanglement network developed at a critical value of molecular weight, Mc, giving a break in the Tll‐versus‐M plots. The present work deals with the influence of dispersity on the Tll transition, below and above Mc. A series of binary blends of “monodisperse” anionically polymerized polystyrenes with systematic changes in M̄n and heterogeneity index (M̄w/M̄n) was tested by TBA. The results show that when both components have molecular weights below Mc, single and average values of Tg and Tll are observed which are linearly related to M̄n−1, as predicted by free volume arguments. Although a single Tg is observed when one component has a molecular weight above and the other has a molecular weight below Mc, the components appear to undergo the Tll relaxation independently. The results indicate that both the glass transition and the Tll transition are basically governed by the same type of molecular motion but at different length ranges.

High Pressure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep, high-pressure light oil reservoirs after waterflooding. The advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas, is its availability at any location. HPAI has been successfully applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their assets.Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteristics of the crude/reservoir rock system. The ensuing estimation of the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical modeling. Typically, the flue gas generated in-situ by combustion leads to in an immiscible gas drive, where the stripping of volatile components is a key recovery mechanism. HPAI has therefore, in some instances, been modeled as an isothermal flue gas drive, employing an Equation of State (EOS) methodology. This approach, however, neglects combustion and its effects on both displacement and sweep. Furthermore, the EOS approach cannot predict if, and when, oxygen breakthrough at producers occurs. Combustion can be included in a limited fashion in simulations at the expense of extra computational time and complexity. In the available literature, combustion is taken generally into account under quite simplified conditions. This paper addresses the role that combustion plays on the incremental recovery of HPAI. Numerical simulations were conducted in a 3D model with real geological features. In order to capture more realistically the physics of the combustion front, a reservoir simulator with dynamic gridding capabilities was used. Kinetic parameters were based on the combustion tube laboratory experiments. The impact of combustion on residual oil, sweep efficiency and predicted project lifetime is presented by comparing isothermal EOS-simulations and multi-component combustion runs.