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

I Remember the Good Old Days…

There’s probably no such thing as a uniform permeability reservoir.  The appearance of uniform permeability comes, to a greater or lesser degree, from an averaging process.  All oil reservoirs show permeability variations, especially at right angles to the plane of deposition.  If the permeability variation is severe it usually leads to channelling from active water drives and water floods.  This necessitates either planning for treatment and disposal of the produced water, or an intervention to reduce water production.

When water flooded reservoirs reach ‘a certain age’ produced water becomes a major problem.   It comes out instead of the oil and can cause sand production with associated erosion, scale formation, impaired lift, and separation difficulties.  In less mature fields the answer to these problems has been to live alongside them or use bulk gels, cement, plugs, straddles or patches applied to tubing or casing.  These usually have to be applied carefully to just the right position in the well using coiled tubing or wire line.  The problem is that, to do a job successfully you either have to be lucky, or know exactly what you’re getting into. Learning about that can be expensive and the most mature reservoirs are also the ones we least want to spend money on.  When the production is only a few thousand barrels a day it’s hard to take a plan seriously when it involves monitoring, evaluation, then a carefully placed treatment.  The sums don’t add up….

What’s Changed?

One answer, developed in the late 1980s, applied in the early 1990s, then improved beyond measure over the last 10 years (1-4), is to use Relative Permeability Modifiers (RPMs) in Selective Water Shut Off (SWSO) treatments pumped down the tubing or annulus from the surface without selective placement.  The chemicals enter the formation and block water flow but are broken through by oil to allow it to produce.  The state of the completion or wellbore or lack of access to it by, for example, coiled tubing, is more or less irrelevant.

The treatments can be selected or formulated for a wide range of salinities and can now be used at temperatures up to 130°C, where the previous limit was more like 90°C (2,3).

Where Do They Work?

Unfortunately, these chemicals can’t work miracles.  If the water is to be blocked and the oil produced they need to be in separate zones (5, 6).  If the water and oil are mixed, in other words if there’s above about 14% of water in the oil, then both will be blocked.  If the water can be diverted into the oil containing zone as shown in Figure 1, it will be and when it reaches the well it will flood previously dry perforations.  This is probably the reason for some short lived treatments seen in the past.  It shouldn’t be assumed that a treatment with a limited lifetime isn’t worth doing.  The incremental recovery can be significant and cheap as illustrated later.

Figure 1 :  Representation of diversion deep in a reservoir leading to limited water shut off treatment life

So how do we know if our problem water producer is a target or not?  We probably have an idea from the history of the field and the well, but a logging run can still look like an expensive investment in a tired old well.

One method used to good promise in the North Sea, is to treat the well using a system that you know will break down.  This is easy at temperatures above about 100°C.  It gives you a chance to see what the results will be without the commitment to a stable treatment.  If it works, then the next time you can afford to use a stable and maybe slightly stronger treatment.

What’s Involved and What are the Results?
The RPM quantities used are well below anything offered by the standard chemical gel treatments and all that is required to apply them is a few tanks and pumps.  The costs are manageable even for fields late in their life and the results can be quite impressive.

 ‘M’ reservoir wells - The results of some treatments on wells of a UK North Sea Upper Jurassic Sandstone oilfield are shown in the table below.  The three wells were producing 3548 bopd with a whopping 32149 bwpd.  After the most recent treatment on each this had been changed overall to 4064 bopd with only 25507 bwpd.

Figure 2: Summary of recent RPM Bullhead Water Shut Off treatments

The SWSO well treatments were piggy-backed onto other jobs and appear extremely competitive on this basis.  An example comes from well M1 where the first three treatments recovered about half a million barrels of incremental oil at a cost of about $0.14 per incremental barrel.  If the jobs had been done in isolation the cost would have been about $0.33 per barrel.

Well H1 - This was the only gas well treated to date.  The pre-job analysis indicated that water was coning into the well and preventing production. 

This was the first case treated in the field and was initially regarded as an unqualified success.  RPM was pumped in February 2003, but the well would not flow and was subsequently shut-in.  When re-opened by the operators in May 2003 it began to flow consistently at good but declining gas rate (see Figure 3 for an approximate rate history) however this ended abruptly in Dec 2003 during a wellhead repair when the fluid level was estimated to be 74.5m above the perforations.  Nevertheless, approximately 2 million cubic metres of incremental gas was produced at a cost of about $0.16 per thousand stock tank cubic feet.  The decreasing effect of the treatment on production was not thought to be due to chemical instability in this relatively cool reservoir, but rather to water bypass of the treated zone.

Figure 3:  Well test history for gas well H1 around RPM treatment

Well W1 - This represented a significant step out in application of the technology, attempting to use a strong treatment to seal off water being produced through fractures into an open hole horizontal wellbore.  It was a stretch target and didn’t work, but a follow up treatment is being planned to place the treatment into the matrix rock beyond the fractures in the belief that this can prevent water entry into them.

Well G1 - This was an interesting treatment because, though it was successful in shutting off water and increasing oil, with payout achieved in only 7 days, the well rapidly sanded up.  The zone without sand control was plugged off and the production then stabilised with an oil rate double the pre – treatment value.  The sudden onset of sanding problems after the RPM application suggests that the two might have been related and that the pressure redistribution near the producing well, caused by the water shut off, might have destabilised the sand prone rock.

Figure 4.  Well test history for well G1

Success?

The set of well treatments described here were commercially inspired but also tested various aspects of the application of two commercial RPM systems.  Though the results, especially on the gas coning case, were sometimes short lived there is good cause to regard most of them as technical and commercial successes as demonstrated in the results table and the discussion.  The data suggest a success rate of 83 to 91%, (depending on whether you include the fracture treatment) which compares well with other water shut off options that are available only when the wellbore is sealed against the formation and access for interventions is possible.

Future Prospects

Sand production is common in layered sandstone reservoirs and degrades the seal between the wellbore and the formation.  This, and unidentified connections between zones are two of the possible reasons why carefully applied and normally reliable water and gas shut off systems, that work all the time in the laboratory or the workshop, work less reliably in the field with success rates of 60 to 70% being normal (7).  RPMs are tolerant of the inability to access the well, the nature of the completion and the bond between the completion and the reservoir rock, so the applicability should be wider than for conventional water shut off systems.  The requirement is that the water and gas should be flowing in separate zones, and how far this is generally true in layered reservoirs needs to be established by study and prudent trials in water prone fields, using temporary systems to test the results before committing to more permanent treatments.

References

1. M. J. Faber, G. J. P. Joosten, K. A. Hashmi and M. Gruenenfelder. ‘Water shut-off field experience with a relative permeability modification system in the Marmul field (Oman)’.  Presented at the 1998 SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK 19th – 22nd April 1998.
2. J Morgan, A Gunn, G Fitch, H Frampton, R Harvey, D Thrasher; R Lane; R McClure, K H Heier and C Kayser.  ‘Development and Deployment of a ‘Bullheadable’ Chemical System for Selective Water shut off leaving Oil/Gas Production Unharmed’  SPE 78540 presented at the 10th Abu Dhabi International Petroleum Exhibition and Conference, 2002.
3. J. J. Wylde, G. D. M. Williams, G. D. Williams, H. Frampton and J. C. Morgan, ‘A chemical solution to increasing oil production whilst minimising water production using polymeric selective water shut off gels’ Paper 3675 presented at the 13th European Symposium on Improved Oil Recovery — Budapest, Hungary, 25 - 27 April 2005
4. A M Gunn, V Money and J C Morgan, ‘The Effect of Hidden Reservoir Chemistry on the Success/Failure of Polymer Squeezes/Floods used in Water Control’  Norwegian Symposium on Oilfield Chemistry
5. Stavland, A., Ekrann, S., Hettervik, K. O., Jakobsen, S. R., Schmidt, T. And Schilling, B.  „Disproportionate Permeability Reduction is not a Panacea’.  SPE 38195 presented at the 1997 SPE European Formation Damage Conference, The Hague, The Netherlands, June 2nd – 3rd 1997.
6. Hettervik, K. O., Jakobsen, S. R., Schilling, B. and Stavland, A.  ‘Water Shut-Off by disproportional reducing gel – a case study’  Paper 045 presented at the 9th European Symposium on Improved Oil Recovery, The Hague, The Netherlands, October 20th – 22nd 1997
7. Mahmoud A. Fotuh and Sameh Macary, ‘Factors That Affect the Success of Mechanical Water Shut-off in Wells’  Paper SPE 62891 presented at the 2000 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, 1–4 October 2000.