Active Pumping of Oil through a Porous Hydrophobic Matrix to Achieve Rapid and Continuous Oil/Water Separation

Section 1. Description of the Proposed Solution

A. Overview

This solution initially stemmed from a method currently used in hydraulic fracturing to separate oil from water using a spongy material (Forbes Magazine, 2012).  However, instead of permanently trapping the oil as that solution does, our proposed solution draws upon an active pumping technique used in oil spill remediation to continuously separate oil from water with high speed, efficiency, and purity.  This solution involves filling the lower portion of an oil well’s string of production tubing with a porous matrix of polyurethane sponges that have been treated with a hydrophobic solution to preferentially absorb oil and repel water.

B. Background and Rationale

In September 2013, a polyurethane sponge coated with carbon nanotubes and poly(dimethylsiloxane) (PDMS) was developed for the continuous absorption and release of oil from water surfaces, delivering oil from water with a purity of >99.97 wt % (Wang and Lin 2013).   Cheaper solutions not involving carbon nanotubes have since been developed; recently (September 2014) a design emerged from Wu et al. using polyurethane sponges surface-treated with TiO2 sol and n-octadecylthiol as hydrophobic agents.  There is a disadvantage, however, to surface-treating; the entire interior of the sponge is not available for the absorption and transportation of collected oil.

The design by Ge et al. stands out in terms of offering the most complete, adaptable, and low-cost system for continuous oil/water separation at high speed.  The design used a pump to apply suction to HPS created from a hydrophobic silica/PDMS-treated polyurethane sponge.  The capillary pressures at oil-air and oil-water interfaces prevented the passage of air and water into the sponge, allowing only the uptake of oil through absorption into the sponge macropores.  The absorbed oil was then pumped into a collection tank, freeing the HPS to take up more oil.

We now describe how this technology, while developed for oil spill remediation, can be applied to substantially reduce the amount of water flow into oil wells.  We first describe where and how it is to be installed, then we describe how to prepare HPS at both laboratory and industrial scales.  Finally we provide estimated costs and references.

C. Installation of HPS

Technical complexity and feasibility; applicability to general use

The HPS will need to be installed within the production tubing near the oil bearing zone but upstream of a filter bed that serves to screen out fine sand and silt.  There, it will form a hydrophobic matrix within the well through which oil will be actively pumped.  The HPS only needs to be present within the joints of tubing near the oil production zone.  A grating should be installed above the HPS to prevent the upwash of the HPS over time due to pumping.

The technical complexity for an existing oil well involves removing the production tubing, installing the HPS within the last segment of the tubing, and reinstalling it.  The process will be easier for a new oil well since the HPS can be pre-installed.  The same pump used to draw oil into the well and lift it to the surface is what will be used to pump the oil through the hydrophobic matrix.  There will be little additional resistance on the pump given the porosity of the spongy matrix.

No discernible impact on public health and environment, or likely regulatory barriers

Both the poly(dimethylsiloxane) and polyurethane components of PDMS-polyurethane HPS have no impacts on public health; due to their non-toxicity they have even been approved for indirect food contact by the FDA (FDA, 2011).   An extensive datasheet on the lack of ecotoxicity, oral/dermal/inhalation toxicity, and skin irritation from PDMS is also available.[1]

Since the HPS is within the last segment of production tubing, it can be efficiently removed along with the rest of the production tubing at the end of the oil well’s life.  Thus there is no regulatory concern with leaving material within the ground that could possibly contaminate groundwater.

Favorable impact on oil recovery rate

After primary and secondary oil recovery, up to 75% of oil may be left in the well.[2]  This system will enhance oil recovery near the well site by preferentially soaking up oil and leaving water behind.  Over time the fluids in the oil-bearing zone will contain a greater percentage of water, but what oil there is near the well site will be captured by the HPS.

D. Preparation of HPS

We start with the base material for the porous hydrophobic matrix – a large quantity of polyurethane-based sponge material.  Polyurethane is low-cost; as an example, a polyurethane sponge can be bought for under $2 at any hardware store for tile grouting, and bulk prices are as low as $0.10 per sponge.[3] To preferentially absorb oil and not water, the sponge needs to be treated with a hydrophobic coating.  We present the initial laboratory-scale process, then provide a version of the process for industrial scale.

Step

Description

Cleaning

Ultrasonically washing the sponge in deionized water and ethanol for 30 minutes to remove possible impurities.

Drying

Drying in an oven at 100°C for 1 h to remove water.

Cutting

Cutting the sponge into smaller sizes (2 x 2 x 4 cm3) for the coating process.

Solution Preparation

Preparation of the hydrophobic coating solution.  This was done by dissolving hydrophobic fumed SiO2 NPs (silica nanoparticles) (0.4 g), Sylgard 184 silicone elastomer base (PDMS) (1.2 g), and curing agent (0.24 g) in n-hexane (30 mL). 

Immersion

Immersion of the pieces in the hydrophobic SiO2 NPs/PDMS solution for 30 s

Airing

Airing of the pieces at room temperature for 6 h to evaporate excess solution

Curing

Curing of the sponge pieces at 200°C for 2 h to yield the final HPS.

The industrial scale process to yield large quantities of HPS is as follows:

1. Cutting

Cutting is necessary to reduce the size of commercially available sponges to a size that can fit into production tubing with diameters of 1-4 inches.[4]  An automatic paper cutter will have a sharp enough blade to automate this process.  We choose to do this step first because it may leave sponge fragments that can be removed in the next step.

2. Cleaning

The goal of cleaning is to remove both physical and chemical impurities that may block the hydrophobic coating from sticking.  To accomplish this at industrial scale we have a physical filtering step followed by a finer chemical filtering step.

Physical filtering: Soak all sponges in a large tank of regular tap water for 1 minute to ensure thorough water take-up.  Then compress all sponges using a flat surface and allow this water to drain.  Refill container with tap water and repeat the process 10 times.  Water should be re-used as much as possible by passing it through a bank of 30 micron sediment filters to remove sponge particles and other impurities.

Chemical filtering:  Use the same pre-filtering process, except transfer the sponges into a container whose water runs through a bank of 5-micron carbon filters instead.  Repeat this rinse process for 5 cycles.

3. Drying

Compress all sponges to drive off the water, then dry in a large oven at 100°C for 1 hour.

4. Solution Preparation

Identical ratios of ingredients should be used as in Ge et al., but scaled up to provide enough coating for the large quantity of sponges.

5. Uptake of Hydrophobic Solution

Compress all sponges with a flat metal surface, then pour in the hydrophobic solution as the compression is being removed.  This will ensure that solution is continuously being drawn into the sponge, minimizing wastage.

6. Airing and Curing

As in Ge et al., the sponges should be aired at room temperature for 6 hours to evaporate excess solultion, then they should be cured at 200°C for 2 h to yield the final HPS.

The thicker the PDMS coating, the longer the HPS will retain its exceptional hydrophobicity.  While a single layer is adequate to create a useful hydrophobic sponge (as described in the following section), if there will be a large quantity of unfiltered silt mixed in with the oil, thicker layers will be desirable.  This may be done by repeating steps 5 and 6 for each successive layer to be added.

E. Durability of the PDMS Coating

This proposed solution uses PDMS-treated polyurethane sponges because of the durability of PDMS and the low cost of the polyurethane sponge on which the coating resides.  PDMS is a chemically inert, non-toxic, non-flammable, and highly flexible material (Choi et al. 2011).  Because of this flexibility, coatings made of this material will be less prone to physical damage over time which will lead to loss of hydrophobicity.

A study using a pure PDMS sponge showed that after long-term immersion in various organics, there was no obvious influence on the hydrophobicity or oil absorbency (Zhao et al. 2014).  Additionally a sponge made of pure PDMS was squeezed and re-immersed in oil 20 times without any change in absorption capacity.  A sponge that is not squeezed but that is allowed to remain in a static state with oil flowing past will last much longer; indeed a PDMS-polyurethane anti-fouling coating has been employed on the hulls of ships where water is constantly flowing by and has shown great durability.[5]

Another durability study was found specifically for a coating of PDMS on polyurethane instead of for pure PDMS.[6]  In this study, aluminum plates were coated with a polyurethane-based binder which was then top-coated with 5 ml of PDMS-treated TS-720 fumed silica, suspended in hexane at 4.2 g/100 ml before curing near 100°C.  This is a similar preparation process to that described in this proposal (as used by Ge et al.).  This PDMS coating on polyurethane was able to withstand 350-850 rubs during manual abrasion testing, which consisted of moving a weight across the coated surface with a reciprocating motion until the majority of water drops placed on the surface did not roll off the surface at the indicated degree of incline.

This degree of incline refers to the contact angle, measured in a test designed to determine hydrophobicity of a surface.[7] This test can also be used to detect changes in hydrophobicity of a piece of HPS over time.  The contact angle is defined by

θ = 2 tan-1 (h/r)

where h = the height of the spherical segment of a water droplet resting on a piece of HPS, and r = the radius of the spherical segment.  If the contact angle is greater than 90 degrees, the water droplet will form a spherical droplet on a flat surface of HPS and roll off when tilted.  The larger the contact angle, the higher the hydrophobicity.

Manual abrasion will reduce the hydrophobicity of HPS over time, but due to the filtering out of fine sand and silt downstream of the HPS within the production tubing, the amount of manual abrasion will be low.  There is sufficient reason to suggest that with mimimal abrasion, the HPS should last as long as the well.  If failure of the coating begins to occur due to heavy abrasion, this will result in increased water production along with the oil but will have no other negative effects on well production.

Section 2. Estimated Costs

There will be $870k of capital expenditures for one plant to create enough HPS to begin installing in wells.  After that, the significant expenses will be plant operations/maintenance costs as well as materials costs.  Combined capital and operating expenditures are $2,270,000, which we show to be under the target cost limit of $2 per thousand gallons processed.

In 2007 the average Bakken well drilled had an average initial production rate of 240 barrels of oil per day during the first 30 days.[8]  This is also a representative value of larger oil wells in many other states including Alaska, Oklahoma, and Texas (EIA, 2009).  With 1 barrel equal to 42 gallons, that is 10,080 gallons of oil per day or 302,400 gallons for the month.  However, wells do not produce at this rate for long; they follow a production curve.  If the output over the next 6 months averaged out to be 50% of that in the first 30 days we would add on another 907,200 gallons for a total of 1,209,600 gallons.

The target cost limit of $2 per thousand gallons produced thus comes out to be $2,419,200 and our solution is under the limit by 6%.  However, this is a very conservative estimate since we are assuming the oil well will only have a 6-month lifetime.  If it lasts for another 3.5 years while producing just 20% of the original level of production, it will add on another 423,360 gallons for a total of 1,632,960 gallons.  The new target cost limit would be $3,264,000 and the cost of our solution would be under this new limit by 30%.

Category

Item

Cost

Notes

Capital expenditures / set-up costs

Process equipment

Automatic cutting machine

Cleaning container for sponges

Motorized sponge compactor

$10,000

$1,000

$4,000

Direct materials

Polyurethane spongesHydrophobic solution ingredients

Physical filtration media (30 micron) Carbon filtration media (5 micron)

$10,000

$20,000

$10,000
$30,000

Buildings/Land

Existing building reconfiguration

Laboratory equipment acquisition

IT system acquisition
(hardware/software)

Acquisition of permits/licenses

$50,000

$25,000

$50,000

$10,000

No land acquisition costs; assumes
minimal building changes required

Labor

Process engineering costsRecruiting and hiring project/plan staff

Salaries prior to opening (1 mo, 10 people)

$100,000

$50,000

$500,000

Minimal
staff for startup compared to actual operation

Total

$870,000

Operating and Maintenance (yearly)

Process equipment

General maintenance of sponge processing equipment $10,000 parts,
$70,000 labor

Direct Materials

Polyurethane spongesHydrophobic solution ingredients

Physical filtration media (30 micron) Carbon filtration media (5 micron)

$10,000

$20,000

$10,000
$30,000

Utilities

Gas for drying sponges

Water for processing

Electricity

$500,000

$500,000

$250,000

Assumes the utility rate will
remain steady from year to year

Total

$1,400,000

Section 3. Key Assumptions

1) There is no installation cost associated with new wells because the installation would be an integral part of the production tubing assembly process.  We also assume that old wells may be retrofitted at a cost commensurate with that necessary to replace the production tubing.

2) There is intended to be no maintenance costs associated with the HPS installed in wells, as the HPS should remain in place for the lifetime of the well.  If this is not the case due to inadequate filtration and sufficient abrasion of the HPS coating occurs to reduce hydrophobicity to an undesirable level, then a maintenance cost should be added in that is equal to the amount necessary to replace the production tubing.

3) Capital costs are estimated from having one plant provide all the HPS for the company’s uses, with minimal building alterations required.

Section 4. References

Choi et al. 2011.  A Polydimethylsiloxane (PDMS) Sponge for the Selective Absorption of Oil from Water.  ACS Appl. Mater. Interfaces 3(12), 4552-4556.  Available at http://pubs.acs.org/doi/abs/10.1021/am201352w; full text: http://bg.bilkent.edu.tr/jc/papers/A%20Polydimethylsiloxane%20(PDMS)%20Sponge%20for%20the%20Selective%20Absorption.pdf.

EIA, 2009.  Distribution of Wells by Production Rate Bracket.  Alaska data available at http://www.eia.gov/pub/oil_gas/petrosystem/ak_table.html.   Oklahoma data available at http://www.eia.gov/pub/oil_gas/petrosystem/ok_table.html.  Texas data at http://www.eia.gov/pub/oil_gas/petrosystem/tx_table.html.  Other states available from main page at http://www.eia.gov/pub/oil_gas/petrosystem/petrosysog.html.

FDA, 2011.  List of Indirect Additives Used in Food Contact Substances.  Last updated 11/14/2011.  Available via http://www.accessdata.fda.gov/scripts/fcn/fcnNavigation.cfm?rpt=iaListing.  CAS number for PDMS: 68937-54-2; CAS numbers for polyurethane: 977104-11-2, 9009-54-5.

Forbes Magazine, 2012.  Shale Gas Frackers Get Excited About … A New Sponge?  Available at http://www.forbes.com/sites/christopherhelman/2012/09/21/shale-gas-frackers-get-excited-about-a-new-sponge/.

Ge et al. 2014.  Pumping through Porous Hydrophobic/Oleophilic Materials: An Alternative Technology for Oil Spill Remediation.  Angewandte Chemie International Edition, 53(14), 3612-3616.  Available at http://onlinelibrary.wiley.com/doi/10.1002/anie.201310151/abstract.

Wang, C. and Lin, S.  2013.  Robust Superhydrophobic/Superoleophilic Sponge for Effective Continuous Absorption and Expulsion of Oil Pollutants from Water.  ACS Appl. Mater. Interfaces, 5(18), 8861-8864.  Available at http://pubs.acs.org/doi/abs/10.1021/am403266v.

Zhao, X. et al.  2014.  Durable superhydrophobic/superoleophilic PDMS sponges and their applications in selective oil absorption and in plugging oil leakages.  J. Mater. Chem. A, 2, 19281-18287.  Available at http://pubs.rsc.org/en/content/articlelanding/2014/ta/c4ta04406a#!divAbstract.

Web References
[1] http://www.rubloffgroup.umd.edu/teaching/enma490fall03/resources/current/publications_etc/pdh-735%28pdms%29.pdf, pages 428-429.  From the Polymer Data Handbook for poly(dimethylsiloxane), available at http://www.toarplast.co.il/linkspage/handbook.pdf.
[2] http://www.oilandgastechnology.net/upstream-news/maximising-recovery-rates
[3] http://www.alibaba.com/trade/search?fsb=y&IndexArea=product_en&CatId=&SearchText=tile+grouting+sponge
[4] http://www.mid-continents.com/production-tubing
[5] http://ndsuresearchfoundation.org/images/pdf/RFT-231%20Flyer%20III.pdf
[6] http://www.google.com/patents/US20120045954, Example 4 and Table 4.
[7] http://www.google.com/patents/US20130209699
[8] http://www.ndoil.org/oil_can_2/faq/faq_results/?offset=5&advancedmode=1&category=Oil%20and%20Gas%20Production

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