Desktop version

Home arrow Engineering

  • Increase font
  • Decrease font


<<   CONTENTS   >>

CO, Transportation

Transporting CO, from its capture point to its destination-offshore CO,-EOR—is an important part of the NG to energy value-chain (Onyebuchi et al., 2018). A reliable, safe and low-cost transport system is a key feature of any CCS project. Depending on the volume of CO„ a variety of transport modals may be utilized, ranging from road tankers to ships and pipelines (Svenssou et al., 2004).

The most used modal is pipeline (Onyebuchi et al., 2018), both onshore and subsea. Continuous flow, ensured by pipelines, is essential when considering the huge flow rates of CO, captured from source facilities. Furthermore, pipelines have proven to be generally more cost-effective in the long-term and are currently being used worldwide (Onyebuchi et al., 2018). Pipelines require rigid specifications, as exposure to CO, eventually leads to corrosion and brittle fractures. Corrosion is due to the acid nature of CO,, while brittle fractures are linked to supercritical CO, leaks (Rabimdran et al., 2011). Impurities in the CO, stream are a serious issue since they can change PxT envelope boundaries, within which a single-phase flow is stable. Presence of moisture above 50 ppm may lead to H,CO, formation inside the pipeline, entailing corrosion potential (Forbes et al., 2008).

To optimize the mass to volume ratio, CO, is earned as dense phase either in liquid or supercritical conditions. Supercritical is preferred when transporting CO, by pipelines, implying that the pipeline operational temperature and pressure should be maintained at supercritical conditions, i.e., above 32.1 °C and 72.9 atm (Jolmseu et al., 2011). The typical pressure and temperature range for a CO, pipeline is between 85 and 150 bar. and between 13 °C and 44 °C ensuring a stable single-phase flow throughout the pipeline (Forbes et al., 2008).

Since supercritical CO, is the preferred state for transportation, very specific conditions of both pipeline and fluid must exist. De Medeiros et al. (2008) developed a thermodynamic model to predict pipeline conditions while accounting for supercritical CO, flow and its characteristic high density and compressibility. CO, pipelines operate at high pressures, high densities, and high fluid compressibility, even in liquid state. That is, CO, can be highly compressible while reaching densities of 900-1000 kg/m3 (de Medeiros and Araujo, 2016).

CO, pipelines have one more critical difference when compared to NG pipelines: CO, flow must occur above bubble-point pressure to avoid vaporization, which would transform the dense single-phase flow into a two-phase compressible flow with lesser total density causing acceleration and head-loss build-up (de Medeiros et ah, 2008). This would generate new difficulties, like greater head-loss per km in the two-phase flow, since the presence of a low-density vapor accelerates the fluid, increasing velocity and pressure, with density loss. In summary, long distance CO, pipelines must operate at high pressures, high flow rates, high density and low velocity (de Medeiros and Araujo, 2016).

The pressure diop due to friction and/or gravitational effects along the pipeline is compensated by adding recompressiou stations. Larger diameter pipelines enable higher flow rates with smaller pressure drops and, therefore, a reduced number of recompressiou stations: however, larger pipelines are more expensive. Hence, a tradeoff exists in which smaller diameter pipelines have lower implementation costs but larger recompressions costs.

Currently, only a few pipelines worldwide are used to cany CO, and are almost all for EOR applications. The oldest one is the Canyon Reef Carriers pipeline, a 225 km pipeline built in 1972 for EOR in Texas (USA). The longest one is the 800 km Cortez pipeline which carries 20 Mt/yr of CO, from a natural source in Colorado to the oil fields in Denver City, Texas since 1983 (Forbes et al., 2008).

Table 6 presents the main existing long-distance CO„ pipelines.

Table 6. Existing long-distance CO, pipelines. Adapted from Seipa et al., 2011.

Pipeline

Location/Start

year

Capacity

(Mt/yr)

Length

(km)

Diameter

(in)

Pressure

(bar)

CO, source

Cortez

USA/'1994

19.3

803

30”

186

McElmo Dome

Sheep Mountain

USA/1983

n a

296

20”

n'a

Sheep Mountam

Sheep Mountam North

USA/1983

n/a

360

24”

132

Sheep Mountam

Bravo

USA/1984

7.3

350

20”

165

Bravo Dome

Central Basm

USA/1985

20

278

16”-26”

170

Denver City Hub

Bad Raman

Turkey/1983

1.1

90

n'a

170

Dodan Field

Canyon Reef Camers

USA/1972

4.4

352

16”

140

Gasification Plant

Yal Verde

USA/1998

2.5

130

10”

n'a

Gas Plant

Bauoil

USA/1986

8.3

180

n'a

n'a

Gas Plant

Weybum

USA/2000

5

328

12”—14”

152

Gasification Plant

n/a - not available.

In Europe, long-distance pipelines for CO, transportation are non-existent. However, more recently, several CO, pipelines har e started operation, with the longest ones being in the North Sea (e.g., 160 km pipeline for Snohvit LNG project) and in the Netherlands (= 80 km pipeline to transport CO, to greenhouses from Rotterdam to Amsterdam) (Seipa et al., 2011).

CO, Conversion to Methanol in FPSO

A solution for ultra-deepwater CO,-rich NG processing, with adjustment of its CO, content still rich in CO„ is to submit it to dry-reforming to produce synthesis gas (SG), which can subsequently be converted to methanol (MeOH). Any unconverted CO, can be further directed to enhanced oil recovery (EOR) in the oil field. Lima et al. (2016) proposed a process with PA (using propylene carbonate as a solvent) due to its easiness of regeneration (a simple expansion valve and a flash vessel). Treating high pressure CO,-rich NG with PA gives two products: (i) a lean, high pressure, NG with low CO, content; and

(ii) a CO,-rich, low pressure, gas effluent. A relevant point in the downstream processing of this CO, rich effluent is that PA has also affinity for hydrocarbons, yet to a lesser degree than its affinity for CO,. This apparent drawback is explored by Lima et al. (2016), since the contaminant hydrocarbons (CH, and C,+) react with CO, via dry-reforming to yield syngas accordingly to equations (2a) and (2b) (Araujo et al., 2014).

The strongest limitation to dry-reforming is the availability of a suitable catalyst, low pressure and a high consumption of heat because the reaction is very endothermic, as seen in equation (2a). Dryreforming also requires high temperature, which contributes to carbon deposition. In CO, reforming, coke deposition on the catalyst is reported to be very fast. However, when CO, reforming occurs simultaneously with steam reforming—i.e., bi-reforming—coke deposition is drastically reduced (Gangadharan et al., 2012). Consequently, operational conditions which, cumulatively, minimize carbon formation and maximize CO, conversion are employed in the reformers. In other words, an appropriate H,OZC (steam- to-carbon) ratio is chosen so that high H,/CO and low СО,/СО ratios result in the syngas product. Hence, coke deposition reactions can be neglected in the analysis, so that bi-reforming encompasses only equations (3a), (3b), (4a) and (4b):

On the one hand, in the case of reformer operating dry-reforming only, the product syngas has a low H,/CO ratio for MeOH synthesis, as seen in equations (2a) and (2b). In this case, the water gas-shift (WGS) reaction in equation (5) can adjust this ratio at the expense of creating more CO, (Gangadharan et al., 2012). Nevertheless, WGS is necessary, because the reactor feed has excess of CO, which would not react to MeOH without H,. Tints, part of the excess of CO is converted by WGS producing H,. This extra H, converts the remaining excess of CO to MeOH. Tire reversibility of WGS is also important, since the H,/CO ratio can be adjusted by manipulating reaction conditions.

Lima et al. (2016) evaluated the combination of dry and steam reforming in one bi-reforming reactor (one pot reactor) and compared this to conversion segregating dry-reforming in the first reactor with WGS performed in a subsequent reactor. Tire second configuration itses a well-proven modular WGS converter. It is worth noting that, besides the environmental motivation, both alternatives were driven by the fact that MeOH is an important chemical commodity, used as raw material in several processes, which would bring economic advantages (i.e., a gas-to-liquids route). The main conclusion of Lima et al. (2016) is that the proposed processes are potentially amenable to a Me-FPSO. This is especially advantageous vis-a-vis the stringent weight and space limitations in FPSO plants. Figure 10 illustrates the conceptual floating process.

Floating process for CO, conversion to methanol

Figure 10. Floating process for CO, conversion to methanol.

Final Remarks

This chapter provides a state-of-the ait review on the main technologies available for CO, management in the context of CO,-rich associated NG, from ultra-deepwater O&G fields. The focus is in the gas- to-energy value-chain, where CO, management starts at offshore decarbonation on FPSOs. This captured CO, is used as an EOR agent, being monetized by the promoted enhancement in oil production (1-3 bbl/tCO,). In the downmost side of the chain, CO, from flue-gas of gas-fired power plants is captured and stored through EOR in the source reservoirs. This cyclic movement of carbon occurs in a nearly closed loop, depending on the efficiency of the carbon capture technology and the distance traveled by carbon. CO, management, in this context, refers to the process system available to maintain carbon in closed loops, shown in Figure 11.

Carbon pipeline distances should be minimized in order to reduce costs and risk of leaks (either of the two molecules in scene). Offshore power generation in floating power generation plants (FPGP) is a technology that introduces the concept of transporting electricity instead of molecules to onshore facilities (GTW) and minimizes the distance of molecule transport.

The main challenge is the NG upgrading (the upstream edge), where the adopted technologies face weight and footprint constraints. To that end, this chapter reviews mostly mature technologies or ones with strong drivers to mature in the near-term. Maturity is approached through TRL, an indicator attributed to each reviewed technology, disregarding disruptive technologies due to their very incipient stage of development (low TRL). The mature or nearly mature technologies in the envisaged scenario are chemical and physical absorption (CAPA), membrane permeation (MP), cryogenic distillation (CD), gas liquid membrane contactors (GLMC), supersonic separators (SS) and hybrid processes (HYB). For each technology, a brief description of the separation method is presented, contextualized in the upstream operation, while highlighting main benefits, shortcomings and recent focus.

CA and PA dominate the NG-to-energy value-chain due to their maturity. Absoiption-based technologies can be applied to both pre- and post-combustion CO, capture with similar results. Despite their proven economic viability, CAPA are plagued with high energy requirements and footprint, solvent toxicity and degradation—thermal (pre- and post-combustion) and oxidative (post-combustion mainly).

MP is optimal for offshore applications, such as CO,-rich NG processing in ultra-deepwaters, due to its modularity, flexibility and lack of solvents, although for very high CO, content in NG, other technologies, mainly the HYB, have a competitive advantage. Various new materials and surface

Carbon management cycles

Figure 11. Carbon management cycles.

treatments are currently being tested in order to improve performance, challenged by the selectivity- permeability tradeoff—MP’s main drawback of highly selective membranes being associated with low permeability and vice versa.

The combination of MP and CA into a single technology yields a new separation method GLMC. Its use intends to maintain CA and MP benefits while removing their major dr awbacks. Nevertheless, GLMC has yet to prove its long-term economic viability in both NG upgr ading and post-combustion applications, thus, research is concentrated on finding better membranes and solvents to enhance decarbonation and reduce wetting.

CD can produce pure and pressurized CO,. CD is commercial in pre-combustion applications, but high cooling requirements have slowed its application in post-combustion. Rigid control is required in order to avoid unwanted column clogging. CD has potentially the best performance in terms of flexibility, as increased CO, content can be compensated for by temperature/pressure adjustments without performance loss.

SS is of great interest in NG processing in ultra-deepwaters as they promote separation in compact equipment. Additionally, SS can promote simultaneous CO, removal, WDPA and HCDPA. On the other hand, due to the CO, freeze-out border, CO, removal from raw NG with 45%rnol CO, can currently limit CO, abatement to 21%mol—requiring a HYB configuration, by adding a CO, polishing process.

HYB consists of combining two or more technologies in parallel or series arrangements. The use of HYB can bypass major drawbacks, increasing flexibility and overall performance. Improvements are derived from cost reductions due to smaller equipment, lower operational costs, lower energy requirements and less stringent separation needs in a single pass. Currently CA-ADS, CA/PA-MP and CD-MP are the most promising candidates, with CD/MP already in commercial scale.

NG decarbonation and post-combustion are completely different CCS applications. While NG processing in ultra-deepwaters requires high pressure CO, removal, flue-gases must deal with low CO, fugacity and high oxygen/nitrogen content. The performance of a given separation technology is greatly affected by the context in which it is inserted. Choosing the correct CO, removal method becomes paramount to avoid excessive costs. A maturity analysis shows that CO, removal from CO,-rich NG is more advanced than from flue-gas with more technologies reaching high TRL numbers.

Furthermore, CO, transportation, both onshore and offshore, has rigid safety specifications that must be met. Thus, attention should be given to the captured CO, properties concerning whether further costly downstream conditioning is required. To reduce overall transportation costs, NG could be directly burned to produce power which is sold to the onshore grid via subsea HYDC cables. This would reduce NG CO, removal requirements as new turbo-sliafts achieve acceptable performance with relatively low-quality NG but increase post-combustion CO, removal needs.

With NG carbon content expected to worsen as CO,-EOR becomes more widespread, stakeholders face pressing decisions as to what technology to use and in what arrangement. By providing a general view on CO, capture from CO,-rich NG on ultra-deepwater rigs, this chapter contributes to design decisionmaking by highlighting the main applications of each technology, factors that affect their performance and what is expected to be implor ed in the near future.

Lastly, a conceptual processing of CO,-rich NG on ultra-deepwater rigs involving CCU by means of chemical conversion of CO, to methanol is presented. Although in very early stage of development, the alternative technology for CO, management holds the potential to be further explored.

 
<<   CONTENTS   >>

Related topics