Impurities

Home>Topics>Impurities
Refine Results
  1. All
  2. Online Articles
  3. Magazine Articles
  4. Videos
  1. CO 2 PIPELINES — Conclusion: Impurity types, concentration influence hydraulic design

    Real CO 2 streams—those from CO 2 -capture plants likely to contain impurities as opposed to pure CO 2 streams—will likely contain at least 95 mole % CO 2 but will also contain impurities generated in the individual power plant and carbon capture-related facilities. The first part of this article (OGJ, Apr. 12, 2010, pp. 39) described in detail methods for determining steady-state pressure and temperature profiles of such CO 2 streams. The conclusion, presented here, addresses the expected influence of impurities present in real CO 2 streams on the hydraulic pipeline layout and presents an overview diagram enabling a first estimation of the most economic pipeline diameter, depending on intended CO 2 throughput rates. Background Type and concentration of the impurity components contained in the CO 2 stream will influence the hydraulic design of a pipeline system transporting real CO 2 streams, which depend on a series of considerations like: • Power plant fuel type and carbon-capture technology. • Health-related safety considerations referring to the maximum allowable concentration of toxic CO 2 stream components (e.g., H 2 S, SO 2 ) in hypothetical leak situations. • Pipeline material-related aspects to limit corrosion (e.g., limitation of H 2 O concentration) or other pipe-material related adverse effects like hydrogen embrittlement of the pipeline steel, hydrogen-induced cracking, or sulfide stress cracking (which can be mitigated by appropriate pipe material selection). • Storage requirements (e.g., concentration limitation of oxygen and noncondensable components). • Limitation of the amount of economically usable additional components transported (e.g., thermal usage of hydrogen or methane). • Limitation of the amount of additional components in order to minimize friction pressure losses or losses of pipeline transportation capacity. • Limitation of the concentration of additional components in order to minimize the amount of energy required in the pipeline system's compression and transportation stations. Impurity sources The process or power plant application for combustion of the primary fossil fuels—coal, oil, gas, biomass, or a mixture of these—determines the CO 2 capture techniques, which for power plant applications are characterized commonly as precombustion, postcombustion, or oxy-fuel processes (Table 1). The processes mentioned may generate components appearing at different combinations and concentrations in the CO 2 streams captured, H 2 S and SO 2 resulting from the fuel's sulfur content. Table 2 gives an overview on the concentrations of the impurities expected in dried CO 2 streams. 1 While the stream compositions given in Table 2 reflect the aspects of the capture processes, Table 3 shows the DYNAMIS specification 2 taking safety and toxicity limits into account. The DYNAMIS report 2 also states, however, that this recommendation covers a capture process applied to coproduction of electricity and hydrogen and, further, care must be used in applying this quality recommendation to other types of capture processes. Impurity influence Estimating the influence of impurities on the pressure and temperature profiles of a CO 2 pipeline system and on the power demand of the initial compression stations and potentially installed intermediate transportation station(s) requires estimating the influence of impurities on vapor pressure-critical pressure, density, viscosity, specific heat capacity, Joule-Thomson coefficient, and isentropic p-T-relationship. The published data on the influence of impurities on CO 2 stream properties, the applicability of existing equations of state, and the applicable mixing rules and parameters data are, however, limited. 3 4 The Polytec report provides example estimates for pressure and temperature-dependent density, dynamic viscosity, and vapor pressure values. 3 The REFPROP program from National Institute of Standards and Technology obtained the data used by the report, referring to the statement by NIST that the program uses the most accurate equations of state currently available. The report 3 comprises a compilation of available measurement data on pressure vs. temperature and vapor-liquid equilibrium data of mixtures of CO 2 with other components. Table 4 presents the influence of impurities on density, viscosity, and vapor pressure of CO 2 streams at 100 bar with different temperatures, using an impurity concentration of 2%. These data were extracted graphically from the report's diagrams and are for illustration purpose only. SO 2 is the only component increasing stream density compared to pure CO 2 , the estimated density for this mixture is very uncertain since no mixture parameters were available. H 2 S has a minimal impact on the fluid density while H 2 has a large impact. Impurities typically will reduce dynamic viscosity (Table 4). Impurities affect vapor pressure with the exception of H 2 S and SO 2 (Table 4). The values for CO 2 -SO 2 mixture are very uncertain, since mixing parameters were estimated and not based on actual measurement data. The presence of impurities also implies the presence of a two-phase region. 3 Table 4 shows, for example, for a temperature of 30° C. (near CO 2 's critical temperature ~31° C.) the vapor pressure of a CO 2 mixture with 2% H 2 is about 8.5 bar higher than that of pure CO 2 . Literature addresses the influence of impurities on critical pressure. 4 Fig. 1 presents the relationships and shows variations of critical pressure of CO 2 streams with different impurities. Fig. 1 shows the increase of the critical pressure due to impurities is expected to remain moderate (<10 bar) if type and concentration of impurities remain in the ranges estimated in Table 2. Fluid properties Estimating the influence of impurities on the results of steady-state pressure and temperature profile calculations assumed modifications of relevant fluid properties of ±10%. Table 5 shows the results of related calculations performed for the hypothetical CO 2 transportation system. Table 5 shows variations of the CO 2 stream density due to impurities as representing a dominant factor in determining pressure losses along a pipeline system. Accurate determination of the CO 2 stream density regarding the presence of impurities therefore represents the major hurdle for reliable prediction of hydraulic pressure and temperature profiles along a new pipeline system for captured CO 2 . The development of a new CO 2 pipeline system requires estimation of the types and concentration ranges of impurity components of the CO 2 stream. Tables 1 and 2 estimates for this purpose depend on the technologies applied for power generation and carbon capture. Table 4 and Fig. 1 can estimate the critical pressure of the transported CO 2 stream, defining the minimum operating pressure by considering the sufficient safety distance to the critical pressure. Table 4 allows estimation of appropriate correction factors for density and viscosity of the CO 2 stream and after selection of an appropriate pipeline diameter, first hydraulic pressure and temperature profiles can be determined applying equations for consecutive pipeline sections from the pipeline system inlet to the system outlet presented in Part 1 of this article. This procedure provides a straightforward methodology to develop basic hydraulic pipeline profiles for new CO 2 transportation systems, respecting also the influence of impurities on the calculated pressure and temperature profiles. Economic aspects After defining minimum operating pressure to avoid two-phase flow, minimizing specific CO 2 transportation costs, including initial investment cost and energy cost to compensate the friction losses, can estimate the optimum pipeline diameter. Assuming a constant annual CO 2 throughput over the life of the project, the specific CO 2 transportation cost C sp can be estimated with initial investment cost C inv , the annuity factor a, the annual energy cost C en , and the annual mass m yr transported (Equation 1). Annuity factor a is calculated as a function of interest rate i and number of operating years n (Equation 2). Initial investment cost C inv depends on parameters including pipe OD, design pressure, pipe WT, steel and coating delivery cost, and pipelaying cost. Estimates for a new CO 2 pipeline system in the 16-32 in. OD range with a design pressure of about 150 bar using typical western European costs of about €39/(inch*m) yield a price for a 24-in. OD pipeline of roughly 39*24 €/m = €936/linear pipeline m. Annual energy costs C en are based on a determination of diameter-dependent friction losses of the specific energy costs to operate the injection-transport stations and the annual operation time of the system. Table 6 shows the main input data used for economic calculations, assuming the CO 2 stream is transported in dense phase at a density of 770 kg/cu m. Fig. 2 shows the results of raw pipeline system optimization. For transportation of 10 million tons/year CO 2 , a 20-in. OD pipeline system would represent the optimum techno-economic solution. The calculated specific transportation cost equals about €1.2/ton at 100 km transportation distance. A 24-in. OD pipeline system could, however, be even more suitable if a future CO 2 throughput expansion were intended (e.g., to 15 million tons/year). The specific transportation cost shown in Fig. 2, however, reflects only the friction-loss related cost along the pipeline route. The specific cost to compress the CO 2 from the capture pressure level to the dense phase has to be added separately to the specific transportation cost. The specific shaft rated power demand for CO 2 compression assuming equal stage pressure ratios as well as isentropic and mechanical efficiencies of 0.80 and 0.90, respectively, is about 366 kJ/kg (1 bar/30° C. to 80 bar) and 21 kJ/kg (80 bar/40° C. to 130 bar). Estimates for the shaft rated power demand to compress 1,200 ton/hr CO 2 from 1 bar to 130 bar in the initial station measured about 122 + 7 = 129 Mw. Friction pressure losses inside the compressor station are not addressed. Assumed specific shaft-rated energy cost of €90/Mw-hr yields a resulting specific compression energy cost of about €9.1/ton CO 2 (1-80 bar) and €0.53/ton CO 2 (80-130 bar). Specific annuity cost of the injection compression station is about €2/ton CO 2 . The intermediate transport station's shaft-rated power demand to increase pressure to 128 bar from 88 bar is about 2.4 Mw, about 1.9% of the compression power demand of the initial station. The curves shown in Fig. 2 provide only a rough indication of optimum diameter for a given annual CO 2 throughput. Determining the optimum solution in each individual case requires more detailed calculations. References 1. "IPCC 2005: IPCC Special Report on Carbon Dioxide Capture and Storage; Prepared by Working Group III of the Intergovernmental Panel on Climate Change," Edited by Metz, B., Davidson, O., de Coninck, H.C., Loos, M., and Meyer, L.A., pp. 442, Cambridge University Press, Cambridge and New York, NY, 2005. 2. "DYNAMIS Project No. 019672: Towards Hydrogen and Electricity Production with Carbon Capture and Storage," D 3.1.3, DYNAMIS CO 2 quality recommendations, June 21, 2007. 3. Polytec Report No. POL-O-2007-138-A, "State-of-the-Art Overview of CO 2 Pipeline Transport with relevance to Offshore Pipelines," Jan. 8, 2008. 4. Seevam, P.N., Race, J.M., and Downie, M.J., "Carbon dioxide pipelines for sequestration in the UK: an engineering gap analysis," Journal of Pipeline Engineering, Vol. 6, No. 3, pp. 140-141, September 2007. More Oil & Gas Journal Current Issue Articles More Oil & Gas Journal Archives Issue Articles View Oil and Gas Articles on PennEnergy.com

    Magazine Articles

    Magazine Articles

    Mon, 19 Apr 2010

  2. Modified cycles, adsorbents improve gas treatment, increase mol-sieve life

    Natural gas treatment often uses adsorbents for contaminant removal. Special materials, such as molecular sieves, remove sulfur-containing impurities like mercaptans, as well as water vapor.

    Magazine Articles

    Magazine Articles

    Mon, 4 Aug 2008

  3. AMOCO PRODUCING IMPROVED PREMIUM FOR MIDWEST MARKET

    Amoco Oil Co. has begun selling in the U.S. Midwest an improved premium gasoline that is refined an extra step. The company said its Crystal Clear Amoco Ultimate, when compared with and without the added refining step, reduces hydrocarbon emissions 13% and has less deposit-forming impurities . The ...

    Magazine Articles

    Magazine Articles

    Mon, 21 Sep 1992

  4. Centurion to link Gelgel discovery in Egypt to Abu Monkar development

    Centurion Energy International Inc., Calgary, said Gelgel-1 well in Egypt was tested from two zones at a combined maximum rate of 31 MMcfd of gas over 72 hr. The test from the two zones was through a 7/8-in. choke with average wellhead pressure of 1,100 psi. The test yielded no water or impurities .

    Online Articles

    Online Articles

    Thu, 16 Aug 2001

  1. AFPM Q&A-1: Safety, gasoline processing questions addressed at annual conference

    Magazine Articles

    Magazine Articles

    Mon, 3 Aug 2015

  2. Market conditions encourage refiners to recover by-product gases

    Segregating fuel-gas blending streams and extracting hydrogen, NGLs, ethylene, and propylene provide a moderate capital cost route for a refinery to improve profitability.

    Magazine Articles

    Magazine Articles

    Mon, 7 Oct 2013

  3. Desert project illustrates selecting acid-gas removal technology

    This article presents criteria that should be considered in preparing a short list of acid-gas removal processes that seem to be appropriate to meet treated-gas specifications. Final selection is on the basis of technical and economic criteria.

    Magazine Articles

    Magazine Articles

    Mon, 6 Jan 2014

  4. Contaminants key to refinery offgas treatment unit design

    This article details methods for removing individual contaminants in refinery offgas (ROG).

    Magazine Articles

    Magazine Articles

    Mon, 15 Sep 2008

  5. Low-cost revamp enhances feedstock profitability for Chinese integrated complex

    In 2010, Liaoning Huajin Tongda Chemicals Co. Ltd. (Huajin), a subsidiary of China North Industries Group Corp. (Norinco), completed a series of retrofits and process flow improvements to maximize the feedstock value of raffinate oil derived from ethylene-cracking at its Panjin integrated refining ...

    Magazine Articles

    Magazine Articles

    Mon, 3 Nov 2014

  6. Study for offshore Mideast field proves inhibitor, sulfur solvent compatible

    Elemental sulfur in the produced gas from Hasbah gas field in the Arabian Gulf off Saudi Arabia raised concerns about flow assurance and corrosion.

    Magazine Articles

    Magazine Articles

    Mon, 6 Oct 2014

  7. Canada sees 78 tcf marketable in Horn River basin

    The ultimate potential for marketable unconventional shale gas in the Horn River basin of Northeast British Columbia is 78 tcf, said a report by Canada's National Energy Board and the BC Ministry of Energy and Mines.

    Magazine Articles

    Magazine Articles

    Mon, 1 Aug 2011

  8. OGJ FOCUS: CO 2 PIPELINES—1: Study details methods for determining steady-state pressure, temperature

    Determining steady-state pressure and temperature profiles of new CO 2 pipeline systems requires both accurate routines for predicting fluid properties and reliable methods of calculating, based on these properties, related pressure and temperature changes along the pipeline route.

    Magazine Articles

    Magazine Articles

    Mon, 12 Apr 2010

Get More Results
Stay Connected