Accepted Manuscript Potential applications of membrane separation for subsea natural gas processing: A review Kristin Dalane, Zhongde Dai, Gro Mogseth, Magne Hillestad, Liyuan Deng PII:
S1875-5100(17)30032-X
DOI:
10.1016/j.jngse.2017.01.023
Reference:
JNGSE 2040
To appear in:
Journal of Natural Gas Science and Engineering
Received Date: 28 September 2016 Revised Date:
26 January 2017
Accepted Date: 28 January 2017
Please cite this article as: Dalane, K., Dai, Z., Mogseth, G., Hillestad, M., Deng, L., Potential applications of membrane separation for subsea natural gas processing: A review, Journal of Natural Gas Science & Engineering (2017), doi: 10.1016/j.jngse.2017.01.023. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
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Potential Applications of Membrane Separation for Subsea Natural Gas Processing: A review
Kristin Dalane, Zhongde Dai, Gro Mogseth, Magne Hillestad, Liyuan Deng*
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Department of Chemical Engineering, Norwegian University of Science and Technology (NTNU),
Sem Sælandsvei 4, N-7491 Trondheim, Norway
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*Corresponding author: Tel: +47 73594112 Email addresses:
[email protected]
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Abstract
The petroleum industry is receiving increased interest in subsea oil and gas processing as it is running out of easily accessible oil and gas reservoirs. Membrane processes fulfill subsea design requirements with a simple and compact design. However, today no application has been used subsea. This paper reviews the advances in membrane separation to date in view of the industrial needs for subsea separation. Some potential applications of membranes and
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membrane processes in subsea processing are proposed based on the topside experience. Two subsea natural gas treatment processes, namely natural gas dehydration and acid gas removal, are discussed in details with respect to the advantages and challenges in the implementation of membrane technology subsea, including future research perspectives. This study can be a
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starting point in connecting the two research areas (subsea separation and membrane
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technology) together. Keywords:
Membrane Separation; Subsea Processing; Natural Gas Dehydration; Acid Gas Removal; Natural Gas Sweetening; Membrane Contactor; Pervaporation
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Contents Abstract ...................................................................................................................................... 1 Keywords: .................................................................................................................................. 1 1.
Introduction ........................................................................................................................ 3
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1.1 The subsea oil and gas production process ...................................................................... 4 1.2 Subsea membrane separation ........................................................................................... 6 2.
Acid gas removal ................................................................................................................ 9 2.1 Membranes for acid gas removal ................................................................................... 10
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2.2 Selection of membrane materials ................................................................................... 12 2.3 Membrane contactor for acid gas removal and the potential for subsea operation ........ 16 3.
Natural gas dehydration .................................................................................................... 22
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3.1 Membranes for dehydration ........................................................................................... 24 3.2 Potential subsea dehydration .......................................................................................... 26
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Conclusion and perspectives ............................................................................................ 33
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4.
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1. Introduction As more than 70% of the Earth’s surface is water, large amounts of oil and gas are located in underwater reservoirs. This leads to the need for a platform or subsea installation to produce oil and gas. After a century of exploration, the petroleum industry is running out of easily accessible reservoirs. It is receiving increased interest in subsea oil and gas processing.
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Subsea to shore could be favorable when an oil reservoir is far away from the coast, in deep waters or in arctic regions where the use of a platform is not an option due to safety reasons or as a tie-in to existing infrastructure and platforms (Albuquerque et al., 2013). An example of subsea process illustrated as “Statoil Subsea Factory” by Norway’s largest oil company is
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given in Figure 1 (Ramberg et al., 2013).
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Figure 1. The Statoil Subsea Factory TM illustration (Ramberg et al., 2013)
The ultimate vision for subsea processing is to transport produced hydrocarbons directly from the reservoir to the market and to avoid further topside treatment (Ruud et al., 2015). The driving force for subsea processing is to maximize the recovery, to increase the production from existing fields and to reduce capital expenditure and operating costs for new installations. In addition, subsea processing can enable the development of new fields that have been left undeveloped due to technical and/or economical limitations, as well as production in harsh environments where platform constructions are not possible (Ramberg et al., 2013; Ruud et al., 2015). Existing platforms often have a limitation in gas capacity, which makes the tie-in of additional fields challenging. Subsea processing of the gas directly into 3
ACCEPTED MANUSCRIPT the export pipelines remove such limitations. Subsea processing also improves safety due to less personal risk compared to a platform, especially regarding fire and explosions (Albuquerque et al., 2013; da Silva et al., 2013). There is no need for fire protection or detection, or fire-fighting systems to protect the personnel.
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For the design of subsea processing systems several aspects are critical. As the process will take place at a remote location, a design for unmanned operations is important without the requirements for rapidly periodical maintenance. High accessibility and retrievability is another important aspect for subsea processing, which favors high modularization of the
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units. In addition, limited moving parts are preferable to reduce the periodical maintenance of the equipment (Daigle et al., 2012; Jahnsen et al., 2011). Due to crane limitations for installation and retrieval (Albuquerque et al., 2013; Orlowski et al., 2012), the subsea
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equipment must be compact in size and weight. Another aspect that should be taken into consideration is that the process should be flexible in order to deal with changes in the flow rates and composition during the production lifetime of the reservoir. Furthermore, operations at high pressure should be possible for the subsea equipment, as high pressure is preferable to
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minimize the boosting and energy requirements (Gyllenhammar et al., 2015).
1.1 The subsea oil and gas production process
Oil and gas production consists of several processing steps from the well to sale products, as
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illustrated in Figure 2.
Figure 2. Overview of the different steps in subsea oil and gas processing.
As a pretreatment step for the bulk separator, the feed from subsea wells might be cooled down. The cooling step has a significant influence on the following processing steps, as it 4
ACCEPTED MANUSCRIPT will change the feed properties and affect the amount of water removed in the bulk separator. The bulk separator separates the feed stream into gas, oil, sand and water. The bulk separation in topside processing normally consists of several steps at different pressures. However, for the currently installed subsea separation systems, one stage is used. The outlet of a bulk separator might be routed to four different branch processes, namely gas treatment,
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oil treatment, sand handling and produced water treatment. Due to the scope of this paper, oil treatment, sand handling and produced water treatment will not be further discussed.
The raw natural gas coming from the bulk separator needs further treatment to achieve the
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sales and transport gas specifications. The treatment process can be divided into two main parts: the removal of contaminants like water, acid gas (e.g., CO2 and H2S) and noncombustible gases (e.g., N2), and the recovery of natural gas liquids (NGLs). The most
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important processing step and the main focus in this paper is the removal of acid gas and water from natural gas in order to meet pipeline specifications, and the potential for doing these processing steps subsea. If pipeline specifications cannot be met, problems with flow assurance and gas transportation may occur, such as hydrate formation and corrosion. The amount of water in the gas from the bulk separator is dependent on the flow temperature and
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pressure, in addition to liquid carry-over from the separator. The required condition for the treated natural gas is a water dew-point of -18 ℃ at a pressure of 69 bar, a CO2 content below 2 mol% and an H2S concentration less than 4 ppm (Christensen and Skouras, 2011; Tabe-Mohammadi, 1999; Tierling et al., 2011). The treated gas is then compressed and
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transported.
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As described above, many of the processing steps include separation to remove impurities. In the natural gas transport from the reservoir to a topside production facility, the injection of chemicals is the common technology today to avoid challenges resulted from the presence of water and acid gas, while in the topside several separation technologies can be used to meet the pipeline specifications. The most used technology for acid gas removal (also known as natural gas sweetening) and natural gas dehydration topside is absorption and adsorption. As these processes have low degree of modularity and are complicated to operate, it is obviously challenging to adapt them for subsea applications. Membrane technology is also a mature technology topside for many separation processes. With the features of being compact, highly modulated and easy to maintain and control, membrane technology fits better with the
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ACCEPTED MANUSCRIPT particular requirements for subsea, which may be feasible for different subsea processing steps, such as natural gas treatment (including acid gas removal and dehydration).
1.2 Subsea membrane separation For subsea processing the main criteria for the process equipment are compact design,
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reliable operation, and low maintenance. The size and weight is important for installation and retrieval, as the lifting crane has a weight limitation, which is dependent on the water depth of installation. To overcome this challenge a compact design and high modularity is required. Moreover, to achieve a low maintenance limited amount of moving parts and low system
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complexity is preferred. In general, membrane separation has several advantages compared to other separation processes, such as a smaller footprint, lower capital and operation costs,
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higher energy efficiency and greater flexibility. Moreover, it is simple to operate, has no moving parts, low environmental impact, and is easy to scale up. New membranes with improved properties can also be easily implemented in existing equipment during planed membrane replacement (Dai et al., 2016a; Kohl and Nielsen, 1997). All the above mentioned membrane advantages should meet the subsea criteria with a great potential for subsea operations. However, there are critical requirements in the selection of membranes and
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membrane modules for reliable performance and long term stability, with much higher standard compared to the membranes used in topside applications. Moreover, as the design of the subsea membrane process should be simple, pre-treatment of the feed is not preferred. Pre-treatment could introduce other complicated processes, or make it impossible to
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implement subsea. There are also many limitations in the design of the process in the selection of facilities; some devices are not applicable for subsea operation, such as vacuum
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pump or advanced controllers, which makes some mature topside membrane process not suitable for subsea applications.
The selection of membrane material for the separation process is critical to achieving high separation performance and to being stable in the long term; It is even more crucial when subsea separation is considered. The membranes can be classified as illustrated in Figure 3.
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Figure 3. Overview of the different classifications of membranes
The membrane material can be polymeric, inorganic or a mixture of those previously mentioned. The different materials have their advantages and disadvantages. Polymeric membranes are widely used as they are easier to fabricate at a lower cost compared to inorganic membranes (Scholes et al., 2012). However, for most polymeric membranes there is a trade-off between the two major performance parameters, permeability and selectivity,
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known as the Robeson upper bound (Robeson, 2008, 1991). An example of the Robeson upper bound for CO2/CH4 separation is shown in Figure 4. A huge number of different membrane materials have been investigated for CO2/CH4 separation. The performances of most of the materials developed before 1991 come under the 1991 upper bound. Great efforts
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have been made to improve the gas permeability and selectivity during the last two decades, and the new materials developed after 1991 made the upper bound move forward and reach a
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new plot known as the 2008 Robeson upper bound. There are some exceptions of membranes with an even higher performance that surpass the Robeson upper bound, such as mixedmatrix membranes (MMMs), facilitated transport fixed-site-carrier membranes (FSC), thermally rearranged (TR) polymers and high free volume polymers.
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Figure 4. Upper bound correlation for CO2/CH4 separation (Robeson, 2008, 1991)(Deng and Hägg, 2010a).
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The membrane fabrication methods and module design also make a big difference in membrane performance. For instance, by ensuring high uniformity with no defects or a thin coating of a selective layer in a composite membrane, the membrane performance may be significantly improved. The possibility of making membrane modules with very high packing
subsea conditions.
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density makes membrane more compact and with less weight and space, which favors the
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The interest in subsea natural gas processing has greatly increased in recent years. The use of membranes for topside natural gas treatment has been widely reported, including several review papers (Baker and Lokhandwala, 2008; Scholes et al., 2012; Sridhar et al., 2007; Tabe-Mohammadi, 1999). However, to the best of our knowledge, no papers can be found on membranes for subsea applications. A review on subsea membrane separation will provide valuable information for both researcher and engineers in the field.
The task of this review is to combine the requirements and criteria for subsea natural gas processing with the progress of natural gas related membrane applications topside, to propose the potential applications of membrane based subsea natural gas processing. This paper 8
ACCEPTED MANUSCRIPT summarizes the advances in membrane technologies for natural gas treatment, including acid gas removal and natural gas dehydration, and discusses in details on the potential and feasibility of membrane separation for subsea applications. An overview of the available literature on membrane processes is given, and future research directions considering the subsea conditions are proposed. We hope that this paper can make the starting point to a new
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interdisciplinary research direction by connecting two research areas (subsea separation and membrane technology).
2. Acid gas removal
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Natural gas is defined as sour gas when, in addition to methane and higher hydrocarbons, it contains H2S and CO2. The CO2 removal is important to increase the heating value and
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energy efficiency of the natural gas (Tabe-Mohammadi, 1999; Tierling et al., 2011). Moreover, the presence of H2S and CO2 in the natural gas together with water will cause serious problems, including corrosion in the pipelines and equipment (Stewart and Arnold, 2011; Tierling et al., 2011). For example, at an H2S concentration of 50 ppm, highly stressed, high strength steel can break in minutes, while under high pressure just 0.1 ppm H2S can significantly reduce the failure time of the material (Amosa et al., 2010). In addition, H2S is a
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highly toxic gas. The removal of H2S to a content lower than 4 ppm is required for safety reasons. Due to the high concentration of H2S in some oil fields and the lack of existing technology with a high selectivity for acid gas removal, these fields are too expensive to
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develop. This leads to the requirement for new separation technologies with high efficiency and low methane loss (Jahn et al., 2012).
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There are four possible acid gas removal scenarios; CO2 removal from gas with no or little H2S, H2S removal from gas with no CO2, the simultaneous removal of CO2 and H2S, and the selective removal of H2S from gas with H2S and CO2. The treatment technology used is dependent on the concentration of H2S and the amount of gas that needs treatment. For high concentration H2S, adsorption processes with amine and sulphur recovery plants are needed. However, if the concentration of H2S is low, the most common method is the continuous injection of non-regenerative scavengers into the pipeline (Kidnay et al., 2011). The scavenger refers to any chemicals that react with sulfide species and make a more inert form. Effective scavenging is based on an irreversible reaction between the sulfide and the
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ACCEPTED MANUSCRIPT scavenger to ensure complete removal (Amosa et al., 2010). The main disadvantage of the use of a non-regenerative scavenger is the cost of the disposal of the used chemicals.
The most common CO2 and H2S removal technology used topside is absorption using either a chemical solvent (e.g., MEA, DEA or MDEA) or a physical solvent (e.g., Selexol process). A
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typical absorption process is a temperature swing process consisting of two contacting towers, one for absorption at low temperature and one for desorption at high temperature. However, as compact technology and high modularity are preferred for subsea separation, an absorption column is challenging to put subsea. In addition, subsea regeneration of the
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solvent is not suitable due to large energy requirements for solvent regeneration (heating) and the need for transportation of rich and lean solvent between the subsea absorption column and
2.1 Membranes for acid gas removal
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the topside of the regeneration column (Gyllenhammar et al., 2015).
The use of membranes has several advantages compared to the other technologies such as absorption and adsorption processes. For instance, the possibility of having a large membrane area in a small module volume due to high packing density allows lower space and weight
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requirements for membrane units for the same production, and consequently reduced investment. Moreover, the process is more environmentally friendly compared to the absorption process due to the non-use of chemicals. In addition to the previously mentioned advantages, membranes also have the advantage of reduced operating costs, no moving parts
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and being suitable for remote locations. Its tolerance of motion makes membrane technology promising for offshore and subsea applications (Jahn et al., 2012; Tierling et al., 2011).
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Several CO2 selective membrane systems for CO2 removal from natural gas have been installed onshore or topside on platforms, as listed in Table 1. For small fields with low CO2 content in the feed, such as the Qadirpur field, membrane systems work quite effectively, and the CO2 content in the product can be quite close to the pipeline specification (< 2%). However, for bigger fields and high CO2 content in the feed stream such as in fields in Indonesia, Thailand and Malaysia, the membrane treated streams still have a high CO2 content (e.g., >6%) and need further treatment. For small fields membrane technologies are economically competitive compared to absorption, while for large fields absorption is still more favorable. However, due to limitations in weight and size on platforms, membrane processes can be more advantageous for offshore or subsea operations. 10
ACCEPTED MANUSCRIPT Table 1. Membrane performance of some installed CO2 removal membrane systems (Cnop et al., 2007).
Gas amount [MMscfd]
Kadanwari, Pakistan (1995) Qadirpur, Pakistan (1995) Salam and Tarek, Egypt (1999) Indonesia (2006) Offshore Thailand (2008) Offshore Malaysia (2007)
210 265 100 245 530 680
Feed Pressure [bar] 90 59 48 52 59 Not given
CO2 feed
CO2 product
12% 6.5% 6% 40% 34% 45%
