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Case Study: Design of Injection Facilities for CO2 Recovery

The graph shows the topography profile across the injection pipelines used in the case study. Source: SPE 185474.

A case study is described in which facilities design is shown to play an important role in providing sources of carbon dioxide (CO2) for the gas-handling process. The challenges associated with bulk CO2 storage, compression, transportation, and injection are also discussed, and an evaluation of existing technologies for CO2-handling facilities is conducted.

Introduction

A company initiated its first pilot project of CO2 injection as a tertiary recovery mechanism in mid-2015. The target reservoir was one of the largest oil fields in the area. The objective of this project was to assess the feasibility of CO2 injection into a carbonate formation and estimate potential additional recoverable oil. The company intended, on the basis of the project outcomes, to set its future strategy for CO2 injection as a tertiary recovery mechanism.

CO2 Injection Challenges. CO2 Source. Because CO2 projects require large investments in infrastructure, a reliable, continuous, accessible source of CO2 is essential for financial reasons. The most common industrial sources of CO2 are power plants, gas-processing plants, and cement plants. The average CO2 emissions out of these plants can reach 11.2 MSCF/MWh (583 kg/MWh). However, CO2 is emitted at concentrations of less than 15%. It requires further processing to enhance CO2 purity. Natural gas liquid (NGL) plants, as well as other types of facilities, produce CO2 as waste-gas streams at much higher concentrations, which make these facilities favorable as reliable sources. Other natural sources of CO2 are available in the form of pure underground CO2 reservoirs. These reservoirs are common in the western US, eastern Europe, and Indonesia, where CO2 purity reaches 99%.

Capture and Storage. Three types of CO2-capture technologies are: (1) Post-combustion capture, in which CO2 is captured directly from the smoke emitted from combustion; (2) oxy-combustion capture, in which CO2 content is increased in flue gases by the use of oxygen instead of air during combustion; and (3) precombustion capture, in which CO2 is removed at the source after converting fuel into a mixture of carbon monoxide (CO) and hydrogen (H2) to form synthesis gas.

Storing CO2 in the subsoil under geological structures is a promising option to limit atmospheric CO2 emissions and can be implemented with other CO2-reduction opportunities. CO2 should be injected at depths more than 2,500 ft to reach the CO2 supercritical state above approximately 88℉ and 1,074 psi, at which it behaves as a single-phase liquid. There are four types of geological formation suitable for CO2 trapping: deep aquifers, depleted or nearly depleted oil fields, oil fields with enhanced recovery, and unmined coal seams.

Deep aquifers offer the largest CO2-storage capacities, 10 times greater than those of oil and gas reservoirs. However, storage in hydrocarbon reservoirs offers a number of advantages:

  1. Low operating cost, because the geology is well known
  2. Reservoirs are already known to be capable of trapping liquid and gases for millions of years
  3. Production and injection equipment are already in place
  4. The CO2 can be used to enhance the recovery of the remaining oil in the reservoir

Dehydration. Dehydration of CO2 is critical because it prevents condensation of free water in the transportation facilities and prevents corrosion in the piping system. Four basic chemical products are used to dehydrate gas: glycol, calcium chloride, glycerol, and solid desiccants (mole sieve and silica gel). The most common dehydration system is triethylene glycol (TEG), which was used in the project.

In some cases, the use of additional dehydration might be economically feasible to recover the hydrocarbon NGLs from the injected rich gas. Three methods allow recovery of NGLs: refrigeration, CO2 fractionation, and membrane separation. Refrigeration is the simplest and least-expensive process. In the project, the purity of CO2 is relatively high and contains no hydrocarbon NGLs because the source of CO2 is a waste-gas stream from an NGL plant.

Transportation. CO2 is compressed and transported by pipeline or cooled on tankers or other ships. However, the only viable option to assure continuous flow is a pipeline. CO2 is gathered in a liquid phase (dense or supercritical). In fact, CO2 is captured at atmospheric pressure at plant sites from flue gases, then dehydrated and pressure-boosted in a dense or supercritical phase to achieve an efficient pipeline transport to the final storage site. It is well recognized that CO2 is noncorrosive if it is in this dry condition.

Scope of the Project

The source of CO2 was identified as the waste-gas stream of the NGL plant, 80 km away from the injector wells. 42 MMscf/D wet CO2 will be captured, processed, and compressed toward four injector wells. To run the project, the TEG CO2 dehydration process was used (Fig. 1).

Fig. 1—Schematic of CO2 capture and dehydration plant.

The scope of the project also includes installation of new compression facilities at the NGL plant to increase the dry CO2 stream from 6 to 1,074 psig to achieve the CO2 dense phase. In addition, a single dense-phase pump will be installed to ship the CO2 toward the injectors.

The temperature and pressure are considered as 140℉ and 6 psig, respectively. The CO2 injection rate was 40 MMscf/D and the wellhead pressure was 2,800 psig.

Design of Dehydration Process

The use of glycols is by far the most common process for gas dehydration. This is achieved by contacting the stream of wet gas with a hydroscoping liquid, in this case TEG. This is a physical absorption process wherein the water vapor dissolves in the relatively pure glycol liquid solvent stream.

The process also consists of a glycol dehydration unit to which heat is added. This step is called regeneration or reconcentration of TEG. The glycol is generated through a boiler where water is evaporated and the glycol restores its pure concentration with minimum losses. Losses of CO2 are expected in the TEG regeneration process because TEG also has an affinity to CO2 that decreases with higher temperature.

Pipeline Network Simulation Model

Commercial software was used to determine the necessary pumping pressure at the CO2 source to meet the 2,800-psig injection pressure requirement at the injector’s wellhead. The total pipeline length was 80 km. The optimum pipeline size was decided on the basis of the maximum gas velocity beyond which erosion will occur (i.e., 3 m/s). The optimum size was found to be 8 in. Because elevation profile influences the pressure-drop calculation, topography was considered when building the pipeline model.

The total CO2 injection rate is 40 MMscf/D (10 MMscf/D per well). The CO2 fluid properties were captured directly from the software’s pressure/volume/temperature database. The pressure-drop calculation is governed by the injection rate, fluid properties, and pipeline material properties. Pressure changes caused by gravity, friction, and turbulence are included in the model. The CO2 properties are dependent on pressure and temperature changes. Pipe roughness-to-diameter ratio is assumed to be 0.0018.

The simulation results show that the pump-discharge pressure at the project’s NGL CO2 source must be 3,416 psia in order to meet the 2,800-psig injection wellhead pressure. The available piping class that can meet this high-pressure requirement is the ANSI-2500 class, for which the maximum allowable operating pressure (MAOP) is 5,789 psia. The ANSI-1500 class cannot be used because the MAOP is 3,474 psia, too close to the modeled discharge pressure. Safety margins must be accounted for as a design criteria. Because CO2 will be dehydrated before its compression and pumping (Fig. 1), the dry CO2 will not cause any corrosion to the inner portion of the pipe; thus, internal coating is not required.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185474, “Design of Injection Facilities for CO2 Recovery Process: A Case Study,” by M. Hossain, Memorial University of Newfoundland, prepared for the 2017 SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, 17–19 May. The paper has not been peer reviewed.

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