The advantages of WAG (water-alternating-gas) injection compared to gas injection and waterflooding, from technical and economical points of view, are results of creating a mixed zone in which both water and gas are flowing simultaneously. Previously, an analytical model was developed in the literature to evaluate complete segregation distance and zone distributions for horizontal miscible WAG injection models. Even though this analytical model is derived using simplifying assumptions, it still gives good insight into the design of new projects when the lack of data does not allow a detailed full field reservoir simulation to be carried out. On the other hand, the advantages and disadvantages of applying WAG injection in dipped reservoirs, and up-dip or down-dip patterns are still in question while there isn't any analytical model available for analyzing process in this type of reservoir. This paper develops analytical equations for a non-horizontal model and investigates the effect of dip angle on segregation effects in miscible WAG injection process. Up-dip versus down-dip WAG injection is another subject which will be discussed in this paper.

Miscible gas injection in oil fields in general results in a better microscopic displacement efficiency compared to water injection; however, higher mobility ratio and lower macroscopic sweep of gas is a major disadvantage compared to water injection. Considering this situation, water alternating gas (WAG) was proposed and implemented as a method to improve macroscopic sweep efficiency of gas using cyclic water injection to reduce its high mobility ratio. In this simulation study, a systematic parameter study was carried out to investigate the effect of different parameters in a miscible WAG process using a horizontal sector model and both black-oil and compositional simulators. The base model was first built using a black-oil simulator but a compositional model was later implemented in order to investigate the differences in results for the two models. This study shows that WAG injection is advantageous compared to both water and gas injection in term of oil recovery factor. Changes of cycle time did not affect the recovery factor significantly while in this particular model recovery is sensitive to the changes of gas half cycle time. It is not possible to find a simple dependency between half cycle time and oil recovery factor but it is obvious that recovery factor is a function of both gas slug size and half cycle time and that an optimum value exists for each case. The effect on recovery by changes in water half cycle time is on the other hand not significant. Injection of water through all layers improved the advance of stable front and improved final oil recovery for all cases. However, the gas injection interval needs to be optimized for each case based on the ratio of vertical and horizontal permeabilities of the reservoir, and thus the injection perforation strategy for gas must take this into consideration. In the model used, which has no aquifer or gas cap, increased dynamic forces by simultaneous increase of field production and injection rates resulted in increased oil recovery. There is good consistency between black-oil and compositional base models with only ±4% OIIP differences in term of field oil recovery.

fax 01-972-952-9435. AbstractThe water coning caused by the imbalance between gravity and viscous forces is the most important reason for water production in different fractured reservoirs. There are various controllable and uncontrollable parameters affecting this phenomenon. In this study different dynamic models were constructed to search for the key parameters affecting the coning process in both single-well and Cartesian multi-well models. It has been determined that oil layer thickness, perforation thickness, fracture permeability and its orientation, especially horizontal not vertical fracture permeability, production rate, mobility ratio, and fracture storativity have the major role in water coning phenomenon. Also it has been determined that fracture spacing, aquifer strength and skin factor have insignificant effect on water coning in fractured reservoirs. The variation of water breakthrough time respect to each effective parameter has also been studied. We concluded that for any production program or adjusting the wells location, the parameter study is very important. Multi-well studies using an Iranian fractured reservoir data show that the trend of dependency of water coning on each parameter is similar to the single-well model. However, in field scale, it is necessary to have all reservoir data including well location, and production history for a successful water coning simulation because a small pressure drawdown exerted by a far well will affect the cone shape and its breakthrough time.

The water coning caused by the imbalance between gravity and viscous forces is the most important reason for water production in different fractured reservoirs. There are various controllable and uncontrollable parameters affecting this phenomenon. In this study different dynamic models were constructed to search for the key parameters affecting the coning process in both single-well and Cartesian multi-well models. It has been determined that oil layer thickness, perforation thickness, fracture permeability and its orientation, especially horizontal not vertical fracture permeability, production rate, mobility ratio, and fracture storativity have the major role in water coning phenomenon. Also it has been determined that fracture spacing, aquifer strength and skin factor have insignificant effect on water coning in fractured reservoirs. The variation of water breakthrough time respect to each effective parameter has also been studied. We concluded that for any production program or adjusting the wells location, the parameter study is very important. Multi-well studies using an Iranian fractured reservoir data show that the trend of dependency of water coning on each parameter is similar to the single-well model. However, in field scale, it is necessary to have all reservoir data including well location, and production history for a successful water coning simulation because a small pressure drawdown exerted by a far well will affect the cone shape and its breakthrough time. Introduction The production of water from oil producing wells is a common occurrence in oilfields. It may be attributed to one or more reasons such as normal rise of oil water contact, water coning, and/or water fingering. The water production increases the operating cost and it may also reduce both reserve and recovery.1 Among these mechanisms, water coning is a serious problem in many oilfields especially in some large Middle East oil reservoirs, where the oil zone has an aquifer underneath whether or not it serves as an active drive.2 Water coning is caused by an imbalance between the gravitational and viscous forces around the completion interval 1. In other words the flow of oil from the reservoir to the well introduces an upward dynamic force upon the reservoir fluids. This dynamic force due to wellbore drawdown causes the water at the bottom of the oil layer to rise to a certain point at which the dynamic force is balanced by the height of water beneath that point (Figure 1). Now, as the lateral distance from the wellbore increases, the pressure drawdown and the upward dynamic force decrease. Thus, the height of the balance point decreases as the distance from the wellbore increases. Therefore, the locus of the balance point is a stable cone shaped water-oil interface. At this stable situation oil flows above the interface while water remains stationary below the interface. 3 The extent of cone growth and/or its stabilization in conventional reservoirs depend on different factors such as mobility ratio, oil zone thickness, the extent of the well penetration, and vertical permeability; but the most important parameter is total production rate. 2 In case of fractured reservoir this problem is more complicated because a dual porosity system results in formation of two cones. Depending on the rates, it may be developed a fast moving cone in the fracture and a slow moving one in the matrix. The relative position of the two cones is rate sensitive and is a function of reservoir properties.4 While there are many theoretical works in the case of conventional reservoirs 5, only limited analytical works are available for the ideal cases of fractured reservoirs such as Birks theory. 6, 7 In fractured reservoirs, critical rate are influenced by extra factors such as fracture storativity w, fracture transmissivity l, fractures pattern and their interaction to matrixes especially around the wellbore. Shorter breakthrough times and lower critical rates are predicted for fractured systems.4 In this study some simulation models have been constructed to analyze the effect of different parameters on water coning in single-well models (Figure 2). Furthermore some models have been constructed to analyze the coning phenomenon in multi-well configuration (Figure 3).

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