The Orinoco Heavy Oil Belt (Faja) has been exploited under primary recovery techniques using mainly horizontal, fishbone and multilateral wells. This cold development can only recover between 6% and 9 % of the considerable original oil in place existing in the area. Owing to the high viscosities, widely different formation thicknesses and heterogeneities found, the implementation of different thermal recovery methods is necessary.This project covers a feasibility study considering the Horizontal Alternating Steam Drive (HASD) process geared to increase the recovery efficiency of heavy oil within the Faja reservoirs. The process is based on a repetitive pattern using horizontal wells acting alternatively as oil producers and steam injectors. The recovery mechanism is a combination of horizontal steam flooding between wells and cyclic steam stimulation of each of the horizontal wells in the pattern. Properly implemented, HASD could be more efficient than classical cyclic steam injection and more effective than direct steam flooding.In contrast to the Steam Assisted Gravity Drainage process (SAGD), HASD uses single horizontal wells cyclically switching between injection and production phases. The steam chamber generated while each well is injecting is laterally driven by the pressure differentials created by adjacent producers, forming a sweeping front between wells. Injectors are converted to producers (and vice versa) providing heat directly to the zones where production will occur gradually extending the steam chambers to the entire reservoir region. Thus, the impact of steam is not that of a simple well stimulation, but also achieves an effective sweep in the vicinity of the producers while decreasing oil viscosity and improving oil drainage.This project is based on the numerical simulation results from a representative model from one of the Faja main blocks using Eclipse Thermal applied to medium thickness sands in the 20-50 net ft range.A five-horizontal well array set up was used as the model to assess this fairly new thermal recovery technique. During the investigation, different scenarios were analyzed to obtain a generalized step-by-step optimization procedure for the process under the specified fluid and reservoir conditions. Sensitivity analyses were performed considering the relative positioning of the horizontal well placement in the reservoir column; different injection sequences; varying the duration of each injection cycle; various injection rates; and lengths of the horizontal reach of the wells.The results of this investigation can be used as a reference to optimize the performance of the HASD process for sand bodies of medium thickness.

The work presented in this paper describes the evaluation and stepwise optimization process for a Steam-Assisted Gravity Drainage (SAGD) project using a representative sector model from a field with fluid and reservoir characteristics from an eastern Venezuela formation.Due to the complexity and number of variables involved in the process, SAGD presents multiple challenges from the design and analysis phases to its final implementation. The objective of this investigation was to understand the impact of key parameters in the process specific to the selected area and to understand the effects on the recovery factor in these reservoirs, which have previously produced with primary recovery mechanisms.The study touches upon the effect of the component grouping for fluid characterization. A preliminary work consisted of reducing the original 14 components identified in the existing Pressure/Volume/Temperature (PVT) analysis into 2 and 3 pseudocomponents and comparing the stability and results using both fluid characterizations to attain reasonable running times in the simulation process.Once the fluid behavior was successfully recreated and the model was set up, a sensitivity analysis was conducted using thermal simulation. The parameters analyzed were vertical well spacing, injection steam rate, well flowing pressure, and horizontal length of the well pair. The effect on the oil recovery from the angle of dip in the reservoir and the orientation of the well pair with regard to the direction of dip were also briefly analyzed.The conclusion presents a highly improved configuration for the SAGD well-pair array that resulted in trebling the oil recovery attained by the initial well arrangement.

An Ecuadorian lease ("Bloque 61") composed of 14 oil fields represents the most productive asset in the country. It contains 5.3 billion barrels of original oil in place (OOIP) distributed in four complex producing reservoirs. After 44 years of production and with a decline rate of 31% per year, maintaining the production from these fields represents an important challenge from the subsurface and execution viewpoints. In December 2015, an integrated service contract was signed with the national oil company (NOC) with a fixed investment for the development of the entire lease. The challenge of the project was to maximize the value of a depleted asset through the framework of the contract. This mature asset has many opportunities to boost production and reserves by implementing an aggressive fit-for purpose development. The opportunities screened and implemented in only 12 months consisted of reaching new oil in appraisal and exploration areas and redevelopment of mature zones with horizontal and infill drilling with mainly reentry wells. Most valuable of all was the implementation of six waterflooding projects. All of these were executed in the Amazon rainforest where there is a pressing need to reduce environmental and social impact. This exploitation philosophy has successfully changed the asset’s production decline, ramping production up from 60,000 BOPD to 80,000 BOPD. This integrated field development plan has amalgamated several technologies with a specific objective of optimizing the value of the asset. The long term was assessed through the drilling of exploration and appraisal opportunities where prospective resources were recategorized to reserves. The medium term was tackled by drilling horizontal wells and re-entries to optimize sweep efficiency and implementing water injection in the main structures. The short term was directed by executing workovers in areas where the water injection was in place. The asset value was recovered and increased as shown by a reserve’s replacement ratio of 1.13. This approach will serve as a framework for the future integrated development of these types of mature assets. The technologies implemented have helped accelerating and optimizing the conceptualization and execution of the project; a few of these include high-resolution reservoir simulation, dumpflooding, closed-loop water source system, and dual-string completions. The integration of strong domain expertise, coupled with advanced technologies and workflows, has led to outstanding results.

The Orinoco Heavy Oil Belt, located in the southern part of the Eastern Basin of Venezuela, is considered the largest deposit of heavy oil in the world. It covers an area of 14 million acres and is characterized by having crude of low API gravity (from 7 to 10º), high viscosity (from 1,000 to 10,000 cp), high porosities (from 18 to 40%) and permeabilities that can reach 30 darcies. Heterogeneity is present in the Faja, there some areas with active bottom aquifers. On these particular areas an early water breakthrough has been identified in some horizontal wells. A numerical simulation model with representative properties of an area of the Orinoco Heavy Oil Belt was defined to assess if the implementation of inflow control devices (ICDs) could reduce water production in horizontal wells. The numerical model contained a horizontal well where these completions elements were installed. The evaluation was made through a sensitivity analysis in which the configuration of the devices and some rock and fluids properties were changed. Additionally, the effect of the horizontal well length was studied as this parameter is relevant in the design and planning of horizontal wells in the Faja. The results of this investigation indicated that the use of inflow control devices can be an effective technology to delay water breakthrough in areas where there is an active bottom aquifer with a good understanding of the geological properties and reservoir behavior. On other hand, this study showed how the differential increase in the cumulative oil of the wells decreases progressively as the horizontal well length section increases. An economic model was created to compare the different simulation scenarios. This research serves as a basis for determining the feasibility of implementing inflow control devices as a water control technology and to obtain valuable information to designing the horizontal section of the wells.