Oil & Gas - Maximising Recovery Programme (formerly SHARP) IOR Views

Background

Hydrogen storage in underground reservoirs could provide a means to facilitate and support the future ‘hydrogen economy’ (1). Since the innovative Downhole Gasification (DHG) technique produces hydrogen directly in the reservoir, avoiding large ‘transfer equipment costs’, it could provide significant cost savings.  Furthermore, the hydrogen mix generated is used as injection gas for maintaining reservoir pressure and to implement GSGI (gravity stabilised gas injection), or alternatively, WAG (water alternating gas).  If applied in the UKCS, the potential oil recovery by these methods is more than 2 billion barrels (2), and additionally, of the order of 0.5 trillion cubic metres of hydrogen is produced by DHG, over 20 years.

Downhole Gasification (DHG) Process

The concept of in situ gasification in conventional light oil reservoirs was first proposed by Davidson and Yule (3), in part, as a safer method of transporting oil (as gas) from environmentally sensitive regions. This envisaged the use of a downhole gasification (DHG) unit(s), connected to a horizontal or vertical well string Figure 1.

Figure1: Downhole gasifer units on a horizontal well string.

The process uses the well-established, low pressure technology, for catalytic steam reforming of hydrocarbons (20 to 30 bar), currently responsible for more than 76% of world hydrogen production of some 50 million tonnes per year.  Permanent gases for oil displacement (mainly H2 and CO2) are generated inside the DHG unit, according to the following reactions;

The reaction stoichiometry favours high temperatures and low pressure.

In a recent research project, the Improved Oil Recovery Group at Bath University carried out simulation and experimental studies (Phase 1), funded by The Scotoil Group (Aberdeen), in order to investigate the feasibility of downhole gasification at high reservoir pressures.

Figure 2: Composition of produced gas from downhole gasifer, Run 02-04 (University of Bath)

Figure 2 shows the trend of hydrogen production achieved by gasifying a light ‘naphtha-cut’ obtained from Statfjord crude oil (42 ºAPI), with added reservoir gas, at 100 bar pressure and 700 ºC (4).  Surface reformer plants normally operate at 20-30 bar and up to 800 ºC, depending on the type of catalyst.  A similar experimental result was obtained when pure n-pentane was used as feedstock (5).  Thus, substantial conversion to permanent gases is achieved, containing around 50%, or more, of hydrogen, at about 130 bar pressure.  Because the reforming reactions are strongly endothermic, electrical energy has to be supplied from the surface.  A process flow diagram for the DHG unit is shown in Figure 3.

Figure 3: Illustrative PDF for DHG Unit

Potential Benefits of DHG

Only about 20% of North Sea oil reservoirs are suitable for GSGI, but more could be produced using a WAG process, especially if higher residual oil saturations could be targeted.  Also, there are many hundreds of light oil reservoirs in the USA (nearing depletion) which are at relatively low pressure, ca. 100 to 200 bar, and would therefore be particularly suitable for DHG.

The DTI has reviewed the use of carbon dioxide as an EOR method in the North Sea, but concluded that it was not economic under present conditions, due to the high cost of capture and transportation.  The unique DHG concept avoids this major problem completely by generating the injection gas in the reservoir, inside a DHG unit(s). The displacement gas produced by DHG is essentially ‘free’, paid for by the incremental oil which is produced. Some of the potential benefits are summarised below:

• Improved oil recovery (GSGI or WAG) not dependent on a source of injection gas.
• No gas compression required, greatly reducing equipment and platform (space) cost
• Improved (incremental) oil recovery via GSGI/WAG effectively pays for hydrogen storage or production.
• Large, strategic inventory of hydrogen available when needed for hydrogen economy.
• Oil recovery maximised by slow GSGI displacement. Depletion down to low oil residual (Sor=0.1) if waterflood residual is low.
• No gas capture or pipeline transport costs.
• Separated CO2 can be exported to adjacent IOR projects, greatly reducing transport cost.
• No gaseous emissions, if only oil produced.
• DHG applicable to onshore and offshore reservoirs, of any size, depending on well availability and suitable gas cap seal.
• Sustainable, clean process, if CO2 used for IOR/EOR and finally sequestrated
• Totally clean hydrogen generation, if electricity generated by wind turbine, or a surface power plant using a fraction of separated hydrogen.
• High reservoir pressure assists downhole or surface separation of hydrogen from produced gas using membrane technology.
• No water contamination, since steam reforming uses clean ‘boiler’ quality water to avoid scaling of heat transfer surfaces
• Suitable for vertical and horizontal wells

Economics of DHG

The Phase 1 experimental feasibility study was conducted using a short tube ‘pilot-scale’ reactor (gasifier).  The short length limited the overall conversion, but this can be improved considerably by loading more catalyst into a longer tube unit.  A basic energy analysis for the process (Table 1) shows that, for 50% conversion of butane to permanent gases (via Equation 1) at 150 bar, 50 ºC, including vaporisation, the ideal production cost (electrical energy), but without heat recovery, is $3.2/bbl.  If the single tube reactor is scaled to well-bore size, approximately 12 m3 of permanent gas (H2,CO2) can be produced at 150 bar.  Including other additions, for OPEX and CAPEX, the total cost of production is around $6/bbl, not accounting for taxes and royalties.  Economics are maximised if no oil is produced, in the medium to longer term.  The process is environmentally friendly, and sustainable, because there are no gaseous emissions. Alternatively, it may be possible to store pure hydrogen in the reservoir and export the CO2 to other adjacent reservoirs, if a method of downhole separation is implemented. Hydrogen could also be co-produced with the incremental oil.  How much gas, or oil, can be produced depends on the size and the number of DHG units employed in a particular reservoir.  It could be a single unit in a ‘back yard’ operation in Oklahoma (or Eakring!), producing 10 to 50 barrels of oil per day, or many tens of units could be installed, producing 100s to 1000s of barrels per day.  A 100 barrel/day unit, with efficient heat recovery, so that there is minimal thermal output from the process so that it operates at essentially reservoir temperature, would require an estimated 100 kW of power.

Table 1: Energy balance for DHG Unit and estimated production cost († Quarterly Energy Prices in Manufacturing sector, DTI. Dec. 2004, P.56, †† $30,000/yr, 10-yr depreciation schedule for DHG unit, well tooling, pumps, water treatment)

Future Developments

Phase 2- A number of factors require further research, in order to prepare the way for the design of a prototype DHG unit and eventual field testing.  Catalyst life is limited by sulphur poisoning and also carbon deposition.  The latter is controlled by using a sufficient steam/carbon ratio.  Sulphur content, if any, is dependent on the particular crude oil, but most importantly what depth of ‘naphtha-cut’ is obtained from the produced oil, as well as catalyst properties and operating conditions.  We intend to investigate these effects in long duration tests, in a series of micro-reactors studies, and also extend the operating pressure to 200-250 bar.  A reservoir scoping study is needed to delineate the ‘best conditions’ for application of DHG, using candidate reservoir data.  A detailed process simulation study will be made to optimise conditions for design of the prototype unit.

Phase 3 - Detailed design and construction of the prototype DHG unit.

Phase 4 - Field pilot testing.

Joint Industry Project (JIP)

The Bath IOR Group will be launching a joint industry project to implement the Phase 2 development, with Scotoil as a partner.  Other industry groups, operators, SMEs and service companies, who would like to participate in a two year project, to gain detailed understanding of the technology, leading to eventual testing and commercialisation, should contact Professor Malcolm Greaves on 01125 386624 or via e mail: M.Greaves@bath.ac.uk.

References

1. Venter, R.D. and Pucher, G., ‘Modelling of Stationary Bulk Hydrogen Storage Systems’, Int. J. Hydrogen Energy, Vol. 22, No.8, 1997, pp 792-798.
2. Jayasekera, A. J. and Goodyear, S.G, ‘Improved Oil Recovery in the United Kingdom Continental Shelf: Past, Present and Future’, SPE 75171, Proceedings SPE/DOE Improved Oil Recovery Symposium, Tulsa, USA, April 15-17, 2002.
3. Davidson, I.D.F. and Yule, A.G., ‘Enhance Oil Recovery by In-Situ Gasification’, International Patent (PCT), No. WO 01/817123 A1, 01.11.01.
4. Final Technical Report to Scotoil, Aberdeen, ‘Downhole Gasification for Improved Oil Recovery’, IOR Research Group, University of Bath, October 2004.
5. Greaves, M, Xia, T.X. and Bentaher, A. H. ‘Underground Gasification for Improved Oil Recovery’, Proceedings 6th Canadian International Petroleum Conference, Calgary, June 7-9, 2005.