Deliverability of gas and liquid hydrocarbons in retrograde condensate systems is highly affected by factors related to both reservoir characteristics and operative variables. It is well documented that pressure depletion coupled with tight petrophysical environments can lead to severe PI decrease due to liquid accumulation initially in the near wellbore area and then in the whole reservoir. Conventional approaches for condensate blockage removal have included the injection of low interfacial tension systems and alcohol blends to promote capillary forces minimization up to levels at which liquid bank gets remobilized. This type of solutions though, can be durability limited as liquid will reform once chemicals leave treated area. This condition become even more critical when static reservoir pressure gets below dew point as liquids from non treated zone will rapidly imbibe into the treated zone decreasing durability even further.The present work documents a field trial of a fluoro polymer technology aimed on Kro and Krg enhancement by rock wettability modification. This technique, as opposed to conventional chemistries working at the fluid-fluid interaction level, is aimed on altering rock`s original wettability. The objective is to promote a neutral wettability condition to minimize capillary effects driven by the contact angle according to LaPlace equation (fig 1).Through a "facts and gaps analysis", a set of root causes are presented to explain the high PI improvement (¬50%) but limited durability observed at field scale. Uncertainties on original rock wettability condition, water saturation profile in the near wellbore, deployment technique effectiveness and chemical properties of size and adsorption are all included in the root cause analysis. Data from pre job coreflood tests, pumping variables behavior and backflowed samples chemical analysis are also incorporated to the exercise. A final set of recommendations derived from the f&g analysis are to be included in further trials of the wettability modification technology where heterogeneous sandstone, compositional condensate environments are present.

Foams have proved to be efficient to block temporarily high conductivity layers, and improving gas injection conformance and sweep efficiency in predominantly matrix reservoir systems, at least at lab and field pilot tests; nevertheless, its successful use in naturally fractured reservoirs has not been fully demonstrated as of today. This paper presents the evaluation process and the successful results for two (2) foam EOR field pilots performed in the Cupiagua in Recetor field; a gas condensate system whose main reservoir is a low porosity (Ͻ6%) quartzarenite with matrix permeabilities in the range of 0.01 to 10 mD, and where the fracture corridors are confirmed to play an important role both in well productivity/ injectivity, and in the inter-well connectivity and gas channelling between gas injectors and oil producers.The reservoir has been developed under massive hydrocarbon gas re-injection, and the current recovery factors of condensate are between 35-40%. The foam treatments were deployed in two gas injectors located in different areas of the field, each one impacting two oil producers, and exhibiting different levels of gas recycling, with GOR ranging between 40,000 and 100,000 scf/STB. Both operations were performed via bull-heading using the SAG method. The results for both jobs showed a temporary reduction in gas injectivity, with slow recovery to its base line within the next 3 months. Despite showing little changes in the injection profile at the gas injectors, the two producers affected by the first job showed a clear change in GOR trends, and a consistent ramp-up in oil production rates during a period of at least 7 months, reaching a maximum increase between 15 and 30 % over their base line productions. The second job was performed to confirm consistency and repeatability of technology, and evaluate duration cycle of blocking and benefit effects. Early surveillance indicates positive response both at the gas injector, and the oil producers. Results herein presented, confirm the viability for foams as an EOR method for this naturally fractured field, and open EOR opportunities for other fractured reservoirs located in the same basin and exploited under gas injection schemes.

Asphaltene deposition related damage is a well known phenomenon during production of highly under saturated volatile oil systems. It's modelling and control has been broadly documented although this last practice has been restricted to the near wellbore region where its impact seems to be maximum and where treatments can be effectively deployed. The following paper presents a modelling approach for the estimation of the asphaltene deposition profile in highly under saturated volatile oil systems. This profile would allow predicting effective permeability loss as a function of pressure provided a set of asphaltene content measurements taken at wellhead through time. A simple asphaltene solubility model coupled with laboratory measurements are combined to propose a precipitation-deposition model that estimates expected k losses when thermo dynamical changes such as methane injection or pressure depletion are present. The output from the model which is a k function of pressure was incorporated into a single well model to match well's actual response after near wellbore dissolution treatments and after injection gas appearance in the drainage area. Laboratory tests consisted of core flooding experiments that allowed obtaining basic relationships between mass of asphaltene deposited and damaged Ko. The present model was developed as a tool for benefit estimation if an asphaltene dissolution technique is applied at reservoir scale. The present approach is proposed as a simple and practical way of estimating asphaltene related damage in compositional volatile oil reservoirs.

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The development of fields located in the Colombian Foothills face important challenges related to fluid compositional character, highly heterogeneous and stressed tectonic environments. Complex and high cost operations make well productivity maximization a key component for an optimal reservoir management strategy. Based on this high risk scenario and on the uncertainties related to complex geological heterogeneities, a coupled simulation excercise has been performed in order to estimate the best engineering solution that allows completing and producing future wells under the optimal scenario of initial and sustained productivity, operational flexibility and mitigation of investment risk. The study herein presented includes a complete sensitivity analysis and uncertainty assessment of four different well completion schemes for production: a single vertical well, a vertical hydraulically fractured well and two multilateral wells, one with one producing branch and other with two producing branches. In all cases, a non-linear hypoelastic constitutive model was fully coupled to the reservoir simulator and permeability changes were included based on its dependence on the mean effective stress. Results suggests that geomechanics effects can lead to significant variations in final recovery depending on completion scheme. This input becomes now critical for final well designs specially in naturally fractured - highly anisotropic zones in which conventional approaches have led to rapid water encroachment and/or near wellbore permeability reduction due to increased effective stress.