This paper describes three different surface facility configurations for an Enhanced Oil Recovery (EOR) project in the Orinoco Oil Belt (OOB), where steam-based, thermal EOR processes are planned to be used at a very large scale. After an initial EOR screening process, four steam-based, thermal EOR technologies werepre-selected as potentially suitable options for the field: Cyclic Steam Stimulation (CSS), Steam Flooding (SF), Steam-Assisted Gravity Drainage (SAGD), and Horizontal Alternating Steam Drive (HASD). In the conceptualization phase, several alternative cases were consideredfor each technology, including variations in injection rates, deployment schedule, and well spacing. All these subsurface cases could be condensed into two design cases for the surface facilities: a low steam generation rate case, and a high steam generation case. However, due to the very large project size and the potential competition with other developments, uncertainty existed about the amount of natural gas that could be available as fuel for the steam generation, as well as about the environmental implications of the EOR operations. To handle these uncertainties, two alternative fuels were considered in addition to natural gas: coke and extra-heavy oil (XHO); a fourth option consisting in a combination of gas and coke was also included in the study. Surface facilities for the two steam generation rates and for the four different fuel alternatives were conceptualized obtaining class V cost estimates. Environmental impact in terms of CO2 emissions and fresh water demand was also evaluated for all the design cases. As expected, natural gas is the fuel that leads to lower cost facilities, as well as to a smaller environmental footprint. On the other hand, in the probable case that not enough gas is available, the decision to use coke or XHO as an alternative fuel will depend on the relative weight given to the economic and environmental factors, which are very related to the EOR technology selected for the field. Thus, this work demonstrates how the integration of the surface facility designs with the reservoir studies allows obtaining very useful insights on the advantages, risks and drawbacks of each EOR technology. This innovative subsurface-surface integrated approach sets the basis for high quality project decisions.

In some of the giant extra-heavy oil fields from the Orinoco Oil Belt (OOB), the challenge is to increase recovery over primary production by about 10%, to meet its ambitious development plan. To get this, it is necessary to apply EOR processes. It is visualized the integral design of a cyclic steam stimulation (CSS) pilot test, using a high steam injection rate. It is identified and quantified the main variables and operational parameters affecting the performance of CSS, for an oil field at OOB. The design of this pilot test covers the location of the area, visualization of thermal well, identification and quantification of the variables that potentially influence to a greater extent the performance of this technology, conceptual design of EOR surface facilities and a complete monitoring plan. A cluster with 10 long horizontal wells of different lengths is evaluated. The variables studied are: specific steam flowrate per unit length of well, well length, and well thermal insulation. We apply design of experiments to select the combinations of the values taken for the different variables. The duration of the different stages in every cycle is given by previous results applying optimization of CSS to sector modeling. The main constrains dictated for the thermal well are identified and taken into account to define the maximum steam injection and production rates for this test. The pilot test is simulated for three complete cycles, with two approaches: High (2.2 – 3 bbl/day*ft) and Low (1.5 bbl/day*ft) specific steam flowrates. Important production variables as drawdown, bottom-hole pressure, field average pressure, gas oil ratio and water cut have been evaluated. Results for the main operating parameters (High/Low approaches), and the economic evaluation, are shown. These results show once again that higher specific steam flow rates get higher recovery and are even more profitable. The study encourages a review of the paradigm that limits steam injection rates in high-productivity projects currently underway at OOB. Additionally, it is identified that at present is the thermal well and not the surface facilities, which limit the application of CSS at higher rates, needing an urgent improvement in its concept. The steam injection rate is conventionally expressed as daily rates (bbl/day), absolute amounts per unit thickness of formation (bbl/ft), etc. This practice creates misunderstandings, especially in the case of horizontal wells. The variable proposed in this study (specific steam flow rate per unit length of well) is valid for any type of well, and it has a physical significance related to well injectivity. Another novelty introduced in this study is a higher specific steam flow rate (2.2-3 bbl/day*ft), between 50% and 100% higher than references found in the literature (1.5-2 bbl/day*ft).