Prior to starting any Enhanced Oil Recovery (EOR) process, it is desirable to characterize the flow pattern within the affected reservoir volume. This becomes of critical importance for in situ combustion in heavy oil reservoirs, where the mobility ratio is highly unfavorable, oftentimes resulting in channeling or early breakthrough. An inter-well connectivity test through immiscible gas injection aids in characterizing the flow distribution, in addition to: 1) calibrating estimates for sweep efficiency, 2) evidencing geological features that may lead to preferential flow towards a particular well or group of them, or lack of connection amongst them, 3) creating a gas path between the injector and producer wells to enable a safe progression of the combustion front, and 4) evaluating the performance of artificial lift and well control systems under high gas-liquid ratio conditions. A connectivity test using nitrogen was designed, implemented and evaluated at the Chichimene field, prior to the ignition of the in situ combustion pilot. This process is summarized and described in this paper. This will be the first in situ combustion trial in a deep (≈ 8,000 ft), extra-heavy oil reservoir, and will serve as a data source to evaluate the development of resources under similar conditions in the eastern plains basin of Colombia. This set of reservoirs bears a significant fraction of the hydrocarbon resources in the country and under Ecopetrol operation. The importance of this pilot makes this connectivity test of even larger relevance to reduce the subsurface and operational uncertainty, identify risks, and increase the probability of success of the combustion process as an option to economically producing these resources.
The screening of chemical EOR technologies for a Colombian field was performed using two different screening tools (weighting averages and artificial intelligence). The Alkali-Surfactant-Polymer (ASP) pilot results were compared with the initial screening studies identifying some weaknesses that are addressed in this paper. Additionally, the use of Lattice Boltzmann pore-scale flow simulation approach to support EOR screening studies is also presented. The screening study was developed using the same input data (e.g. pressure, temperature, porosity, permeability, oil gravity, and viscosity). Screening results and potential reservoir analogs identified using both systems were compared, including the evaluation of the geological parameters that are normally missing in most of screening studies. The results are compared with the ASP pilot performance to validate the effectiveness of conventional screening studies overlooking geologic information. In addition, the results were also confirmed evaluating ASP field cases reported in the literature. Finally, the use of digital rock analysis using micro CT scan images to support ongoing screening results is presented. Screening results obtained using different screening tools were similar identifying the EOR recovery process (e.g. Chemical EOR). However, the screening results excluding the evaluation of geological parameters such as rock cementation (e.g. sandstone formations with carbonate cement) did not prevent the selection of ASP flooding as an EOR recovery process for the field under study. This was confirmed with the severe scaling problems observed during the ASP pilot test implemented in Colombia as well in Canadian ASP floods. This paper describes the main steps for conducting robust EOR screening studies, including the use of Lattice Boltzmann pore-scale flow simulation to evaluate preliminary performance of oil recovery processes (e.g. waterflooding, polymer and surfactant injection) that contributes to field evaluations and experimental lab design. The proposed screening approach will contribute identifying the technical and economic EOR potential (from exploratory appraisal to mature field rejuvenation) under conditions of limited information and time constraints.
A great portion of the produced oil currently comes from mature fields, reason why the increase in oil production of current reservoirs is the main objective of oil companies. Thermal enhanced oil recovery processes have been studied, implemented and improved over the years. In the last decade there has been significant interest in the light oil air injection (LOAI) process since the successful implementation of the process known as High Pressure Air Injection in the Buffalo Field (USA), which is a variation from the air injection process in light oil, applicable to deep reservoirs with low permeability and porosity. Proof of this are the West Hackberry Field (USA), more than five commercial projects along the Willinston Basin (USA) and recently a pilot in the Zhong Yuan Field (China). Additionally, feasibility studies have also been initiated and performed in Mexico, Argentina and Colombia. This article proposes screening criteria for the selection of potential light oil reservoirs to be candidates for air injection, as well as a general methodology for the prioritization of the reservoirs with the highest LOAI implementation potential. Said methodology employs screening criteria, analogies and numerical simulation. The first part goes beyond the binary screening by assigning a weight to each one of the criteria, therefore resulting in a numerical ranking. For the analogies the reservoirs in which the technology has already been applied are grouped in four group types, against which the field on evaluation is compared. There is also a numerical simulation in 1D – 2D, where the injectivity with or without pressurization is evaluated, as well as the displacement stability. Additionally a multi-criteria evaluation method is used to select the best candidate.
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