Successful Field Application of a New Selective Water Shut Off System

Williams G (Clariant Oil Services, UK), Morgan J (Jimtech, UK), Wylde J (Clariant Oil Services, UK), Frampton H (BP Exploration, UK)

Abstract

The paper describes a series of three field applications of a new selective water shut off (SWSO) system on the BP operated Miller field. The target well was a vertical cased and perforated producer in the UKCS, with a reservoir temperature of 121°C and permeability in the range 100-1000mD. All of the treatments reduced water production, in one case by up to 6000 bpd (a 60% reduction). Furthermore, oil production was simultaneously increased by up to 150%. Payback time for the intervention costs was typically a few days, with the treatment benefits lasting up to six months. All of the treatments had to be designed and applied without any PLT data available to show where the water was coming from in the reservoir. This low concentration, non-hazardous chemical treatment has been developed for pumping from surface to significantly reduce water production without harming hydrocarbon production. It is possible to apply it to an extremely wide range of reservoir targets, the system working from 20mD-16D and from ambient up to 130°C. This makes it of more general applicability than previous SWSO systems, especially in its ability to treat high temperature and high permeability targets. Further jobs are now being planned in a range of wells. This case history demonstrates the ability i) to use selective water shut off to treat wells where there is a high degree of uncertainty and so no other option for water shut off; ii) to design an initial treatment to manage risk in such cases; iii) to learn from initial outcomes and improve treatment performance on repeat applications.

Introduction

Water production is a major problem world wide, with 3 barrels of water being produced for every barrel of oil. Costs associated with produced water will depend on the situation, but can be significant and include

• Direct costs of production, separation, treatment and disposal of unwanted water.• Problems directly related to water production, such as scale, corrosion, sand

production.• Decreased hydrocarbon production rate caused directly by water production, due

to either increased hydrostatic head in the well or to processing constraints on produced fluid volumes.

• Loss of reserves due to bypassed oil, loss of reservoir pressure, or inability to lift wells with very high water cut.

Reducing water production can also reduce environmental impact. Despite improvements in produced water quality, there will typically be a significant amount of hydrocarbons

and also often production chemicals remaining in this water. Reducing the total volume of disposed water is therefore the most certain way to reduce emissions of oil and chemicals into the environment. Reduction of water production will also reduce the volumes of chemicals which are consumed to control water related problems such as scale or corrosion.

Traditionally, excess water production has been dealt with by placing an impermeable barrier in some part of the well or reservoir to prevent the fluids from a single part of the formation from reaching the production tubing. These systems (here referred to collectively as mechanical methods) fall into two categories. Firstly there are mechanical devices which are placed in the wellbore. These include plugs, which are set across the wellbore to block off the bottom section of the wellbore to stop bottom hole water, or expandable patches or other devices, which seal off a single perforation set. Secondly, there are fluids which are pumped into the producing formation, which then solidify into a totally impermeable barrier to seal off that part. These include cements, rigid (impermeable) polymer-based gels and a wide range of other chemistries.

Although potentially very effective, these approaches have several collective limitations.

• They must be placed specifically in relation to the water source. Plugs and patches will generally need to be placed on wireline. Cements or rigid gels are pumped through coiled tubing, placing packers to isolate the target zone and so protect the rest of the formation during treatment. In either case this requires the use of potentially expensive downhole equipment, and so these solutions can fail to be cost effective

• It is necessary to know the precise source of the water in the well, in order to correctly locate the solution. This may require the collection of production logging data, which is again potentially costly and may not always be possible to obtain.

• They can be high risk if the assumptions made are incorrect. If placed on the hydrocarbon-producing part of the well they will inevitably damage production, and the only remedial option may be to re-drill or re-complete the well.

• It is not possible to use them on difficult to access wells, for example subsea completions or where there is a fish in the hole.

• Some completions may prevent their use, for example a plug will not work in an openhole completion (as fluid could simply migrate round it), or where water enters the production tubing via a leak behind the casing.

There has therefore been a historic requirement for low risk, cost effective solutions for water shut off, especially for low value or difficult to access wells, or wells where there is limited information available regarding downhole conditions. An alternative approach for these cases is to deploy a chemical system into the formation that does not totally block

fluids, but has some kind of selective mechanism that will allow oil or gas to flow while hindering water production (figure 1).

This approach can potentially overcome many of the limitations listed above because the system works by a selective mechanism. It is not necessary to place it into a specific part of the formation and systems can therefore be deployed by bullheading through the production tubing, giving more potential for a cost effective treatment. Furthermore, it is not absolutely necessary to know where the water is coming from within the well, so these treatments can be deployed without the need for production logging data. Finally, because no downhole equipment is required, they can usually be pumped regardless of constrictions or obstructions in the well.

One way to do this is to use a polymer which absorbs on the surface of the producing formation. This makes the rock more water wet and so reduces the relative permeability of the formation to water compared to oil. These systems are generally called relative permeability modifiers (RPM). However, this approach is limited because the polymers only form a surface coating. To give a strong effect it is therefore necessary that the pore throat size be no more than twice the thickness of a monolayer of polymer. If the pore throat diameter significantly exceeds this then fluid can still flow easily through the centre of the pores and the effectiveness of an RPM becomes limited. It is theoretically possible to increase the monolayer thickness by increasing the polymer size, but in practice high molecular weight polymers are easily damaged during pumping. These systems are therefore limited in practice to systems where the pore throat size is relatively small, i.e. generally to lower permeabilities.

The alternative approach described here is to deploy a medium molecular weight polymer combined with a cross-linking agent which reacts with the polymer in situ. Use of the cross-linking agent allows an open, three-dimensional polymer network to build up across the entire pore space. It also allows use of a relatively low molecular weight polymer, which is easier to handle in the field.

The initial development work on the polymer / cross-linker system used has been described in a previous paper 1. Some initial field applications were also described, using a sequential deployment method. This method involved pumping the polymer and cross­linker in separate stages, and back-flowing the well to superimpose the two components in the reservoir. These field trials demonstrated the potential of the system. However, the method used was believed to be more complicated than is necessary, especially for cases where there are significant variations in the injectivity of the formation. Further development work was therefore carried out to test a co-deployed system, in which the polymer and cross-linker are deployed together as a single stage treatment. This involved use of a more sterically hindered polymer, which is relatively slow to react with the cross-linker at ambient temperatures. The two components can therefore be mixed together at the surface for injection as a single stage treatment. After injection the fluid heats up in the reservoir, causing the components to react. The applications described in this paper represent the first field application of this redeveloped single stage system.

Field Conditions

The initial target was well A18 (slot 32) on the BP operated Miller field, an offshore UKCS platform. Pressure support on the field is by sea water injection, and over time an increasing amount of injected water has been seen at the production wells. All of the wells currently produce significant amounts of water, typically above 75% and in some cases up to 99% water cut. The formation water in the field has an extremely high barium content, so the producing wells mostly have an extremely severe barite scaling problem. This is countered by performing downhole scale squeeze treatments to protect the wells.

However, because of harsh nature of the problem, the lifetime of the squeezes can be extremely limited, in some cases no more than 7-14 days. Any reduction in produced water rate would effectively increase the lifetime of the squeezes, since the scale inhibitor would be returned more slowly. There is therefore a large potential for water shut off to create economic benefit 2-5.

The target well is a vertical producer, cased and perforated with 200’ of producing interval. The producing formation consists of layered sandstone and shales. Permeability in the producing layers is mostly in the range 100-200mD, with isolated streaks of up to 1D. Porosity was typically 22%.

The reservoir temperature on the field is 121°C. At high temperatures the lifetime of the polymer gel is relatively limited due to thermal hydrolysis of the polymer chains. At this temperature, the lifetime of the gel is not more than 6 months, so there was a requirement for repeated treatments. A series of three treatments was therefore applied over a period of 18 months, treatments being timed for when the gel was expected to have fully broken down, depending also on operational constraints

First treatment 13th May 2003Second treatment 16th January 2004Third treatment 4th October 2004

Treatment Design

As highlighted, a key advantage of selective water shut off over mechanical water shut off is that it can be applied without knowing where the water source is. However, lack of knowledge will still generally mean higher risk. Although the chemical system has a selective permeability mechanism, application is still limited to situations where there are distinct oil and water streams in the reservoir. If the remaining oil production is being swept through the reservoir as isolated droplets in a continuous stream of water then shutting of the water must inevitably shut off the oil to the same extent. This is an absolute, physical limitation that applies to all methods of water shut off.

A18 was initially assessed as likely to contain distinct oil and water, based on the known reservoir structure and production history. It was believed that the water production on

this well is due to formation water breakthrough in the higher permeability layers, with dry oil production remaining in some of the thinner and / or lower permeability sands. However, no production logging data was available for the well, and it was therefore necessary to design the initial treatment without confirmation of the fluid inflow pattern into the well.

To manage this application risk, the performance of the co-deployed system was investigated in the laboratory using field specific long sand pack tests as described below. It was found that the properties of the system can be altered by increasing or decreasing the concentrations of polymer and cross-linker used. The higher the concentrations, the higher the reduction in the effective permeability to water, and therefore the greater the degree of water shut off which will be expected. However, a concentrated treatment that would give a high degree of water shut off would also cause more damage to oil production (and be harder to remediate) in the event that the oil and water do not form distinct production streams in the reservoir.

The laboratory test data were used to select a set of volumes and concentrations to give a relatively low level of water shut off for the first treatment. The first treatment was therefore intended to demonstrate the potential for water shut off while minimising the risk of damage to the well. As is discussed later, the first treatment did demonstrate water shut off on this well without damaging oil production. The second treatment design was then based on the outcome of the first treatment: given the increased confidence from the first result, the second treatment contained a polymer concentration 50% higher than in the first one. Again as is discussed later, the second treatment gave improved performance compared to the first. The third treatment was therefore a repeat of the optimised second treatment.

In effect therefore, the initial treatment not only gave some production benefit but also functioned as a cost effective alternative to collecting production logging data. By shutting off water without damaging oil production, the treatment demonstrated that the water and oil production are distinct within the reservoir. This is a key benefit of this approach to water shut off: in situations where a well is inherently high risk or where data is very limited, the treatment can be designed as a ‘diagnostic’ treatment to demonstrate the suitability of the well for future, more aggressive water shut off treatments.

Laboratory Testing

A sand pack consists of a length of stainless steel tubing filled with sand (or other material) to simulate a section of reservoir. In these tests the packs were 1.5m long and 6mm internal diameter, but other lengths or diameters can be prepared depending on the test application.

This approach was used instead of core testing, as it allows the in depth penetration of the system into the reservoir to be investigated, albeit in linear flow. A core is typically limited to no more than a few inches, whereas the sand packs used were typically 1.5m

long, corresponding to the full depth to which the treatment fluid is pumped in the reservoir. Since the behaviour of the system is critically dependant on the reaction between polymer and cross-linker, which is time and temperature dependant, this means that a core test will provide very limited information on the behaviour of the system. Although the sand is not field specific, the material is sized to give a specific permeability, and other components can be added where required to mimic specific core compositions.

To prepare a pack, dry material was put into a vertical length of stainless steel tubing, tapping the tubing to help it settle properly. The required permeability of a few hundred mD was obtained by selecting a sand fraction with a particle size range of around 50-200 microns. The packed tubing was then coiled and placed in a thermostat oven used to set reservoir temperature. Coiling also axially compressed the sand, which prevented any sand movement or fluid channelling through the pack during the experiment. The standard sand-pack flood sequence was then as follows.

Firstly, flooding from the “reservoir” end, to condition the pack

• Carbon dioxide, to displace air• Formation water, until pressure drop across pack is stable• Crude oil to reach residual water saturation• Produced water to reach residual oil saturation SORw

Secondly, from the “well” end, to simulate the treatment

• Inject one pore volume of chemical treatment• Shut-in overnight to allow to react

Finally, flooding from the “reservoir” end

• Produced water at constant pump rate, to determine effective permeability after treatment

• Optionally, scale inhibitor to check compatibility of the gel with the inhibitors used on the well

• Optionally, crude to check the clean up of the gel

The results of these tests are illustrated in figure 2.

Deployment

The system was deployed into the well by bullheading through the production tubing, in a similar manner to established methods for scale squeezes. The system was supplied as a series of aqueous concentrates: a polymer concentrate, a cross-linker concentrate and a buffer solution to regulate the pH of the formation during pumping of the chemicals. These three chemicals were pumped via separate dosing pumps (figure) into a sea water

injection line for injection downhole. The total downhole injection rate was typically between 5 and 8 bpm.

The first and second treatment dates coincided with a scale squeeze treatment being required on the well, and this was deployed in combination with the water shut off treatment. This provided a cost effective method to pump two treatments at once without increasing the deployment costs. In particular, the shut in time for the treatment was no longer than would have been required for the scale inhibitor squeeze, so there was no deferred oil cost associated with the water shut off treatment. In effect, the treatment forms the final part of the overflush for the scale squeeze, the only extra cost for the water shut off being that of the chemicals.

The general sequence was as follows:

1. Preflush. Sea water containing no chemicals except for additives to avoid risk of formation damage.

2. Scale inhibitor squeeze, with an overflush to displace it out into the reservoir (first and third treatments only).

3. Main treatment. Sea water containing the water shut off chemicals.4. Tubing displacement. Sea water containing small amount of scale inhibitor.5. Shut in for 12 hours to allow cross-linking.6. Back produce well by standard procedure.

The preflush was required to cool the temperature in the production tubing to below 70°C to ensure that the treatment fluid did not react before it reached the reservoir. Because of the high reservoir temperature, a relatively large volume of injected fluid was required to achieve this. Where a scale inhibitor squeeze was included this provided the cooling effect, and so a small preflush volume was sufficient; where there was no scale inhibitor squeeze (third treatment) the preflush was required to be increased. The second treatment was also preceded by a scale dissolution treatment. However, the well was back produced between this and the water shut off in order to ensure that a proper comparison of pre- and post-treatment production rates could be made.

The displacement stage was designed to push the main treatment out of the production tubing and into the reservoir, but no further, leaving the treatment fluids in the formation immediately adjacent to the wellbore.

In all cases the treatments were pumped as intended, with the pump rate for most of the treatment being 6 bpm. Some pressure build up was seen during injection of the main treatment and the displacement stages, and in some cases the pump rate was consequently reduced to 4 or 5 bpm.

On all occasions the well was back produced without any observable adverse impacts. The treatment fluids are non-aggressive, and as expected caused no compatibility issues. Furthermore, no impact was seen on the oil in water.

Treatment volumes bbl

1 2 3

Preflush 200 200 1250Sale inhibitor squeeze 514 (20% SI) 514(20% SI) -

Overflush 1250 1250 -

Main treatment 780 780 780Tubing displacement 331 330 330

Shut in time 12 hours 12 hours 12 hoursPump Rate 6 bbl/min 4-6 bbl/min 5-6 bbl/min

Table 1. Treatment design summary.

Results

In all cases the well cleaned up as rapidly as has been previously observed after stand­alone scale squeeze treatments. This allowed good comparisons of production rates immediately (1-2 days) prior to and after each treatment. For the first and third treatments, well tests were performed immediately before and after to establish the effect of the treatment. However, at the time of the second treatment, the test separator was not available. The rates given for the second treatment were therefore deduced from export and overboard volumes in this case. Gas lift rates and choke settings remained the same before and after each treatment. The results for all three treatments are summarised in table 2.

Treatment 2Before After Before After Before After

Oil rateBpd

413 1147 728 1378 1500 2000

Water rate Bpd 9795 9415 9901 4135 8000 7000

Change inOil

+179% +89% +33%

Change in Water -4% -58% -13%

Total fluids bpd 10208 10562 10629 5513 9500 9000

Water to oil ratio 217 8.2 13 6 3.0 5.3 3.5

Water cut / % 96 89 93 75 84 78

Table 2. Summary of production rates pre- and post-treatment.

Discussion

The results for all three treatments show a consistent reduction in produced water as a result of the chemical treatment. In the case of the first treatment the effect was relatively small (4%), but this result was found to be consistent across several well tests and so was believed to be a small but statistically significant effect.

By the time of the second treatment (8 months after the first) the water production rate had increased again and it was believed that the gel had fully broken down. As highlighted previously, the second treatment contained 50% more polymer than the first, in order to achieve a higher level of water shut off. This expectation was borne out in the result: the second treatment achieved a 58% reduction in the water production rate, representing a reduction of almost 6000 bpd. Furthermore the benefit was longer lived; even nine months later the water production rate from the well was 2000 bpd lower than it had been immediately prior to the second treatment.

Given the success of the second treatment, the third treatment was designed using the same chemical concentrations as the second. Although the third treatment caused a significant reduction in water production (-15%, or -1000 bpd) the effect was less than for the second. This highlights the uncertainty in predicting the outcome of bullheaded treatments; it is probable that changes in the injectivity pattern may have led to a smaller proportion of the injected fluid reaching the target water producing zones on this occasion. However, given the increasing confidence in the rapid and complete clean up of the well after application of these treatments, a future treatment is planned with significantly increased chemical concentrations to further optimise the performance.

The results of all three treatments also show a consistent, and in some cases dramatic, increase in the oil production rate. The combined effect of the treatments has been to increase the oil production rate from 400 bpd just before the first treatment to 2000 bpd immediately after the third treatment. The percent increase was greatest for the first treatment (+179%) and least for the third treatment (+33%). While some increase may be expected due to increased lift as water cut is reduced, the increases observed are much greater than can be explained by this and so must indicate some kind of stimulation mechanism taking place. Furthermore, it is observed that between treatments the oil rate declined significantly, but that it never declined to its pre-job levels. This suggests that there is a combination of two mechanisms operating, one of which is related to the actual and ongoing presence of the gel (which would provide extra oil production only as long as the gel persisted) and one of which is a stimulation process in the near wellbore region (which would provide extra oil on an ongoing basis). Unfortunately, given the limited available downhole data it is hard to prove a specific mechanism for the extra production. However, it is suggested that

1. The temporary element of the increased production is due to the gel acting to divert water away from the water-swept high permeability channels and into lower permeability channels which are previously unswept.

2. The ongoing element is due to a near wellbore alteration of the formation properties as a result of the treatment. This could for example be due to removal of carbonate scale by the acid buffer deployed as part of the system, although it was not believed that any scale was present. Alternatively, the treatment may have removed a water block or other water-related damage mechanism (it is known that there has been water related damage on the Miller field, although the mechanism is unknown).

It should also be noted that the fact of stimulation makes it harder to absolutely assign the level of water shut off obtained. If the water-producing formation has also been stimulated then the water productivity would be expected to increase: the reductions in water production rates claimed here therefore represent the minimum reduction in water productivity caused by the gel. For example, a 4% water shut off effect is claimed for the first treatment from a comparison of actual production rates. However, if it is assumed that the +179% change in oil production indicates a stimulation of the entire producing interval then the baseline water production rate should also be considered to have increased by 179%. The water shut off effect would then have to be a 65% reduction in water productivity to give the overall observed reduction of -4% in the water production rate.

Conclusions

These treatments have demonstrated

1. This system can effectively shut off water without damaging oil production2. This system may also have the ability to stimulate oil production3. The ability of this selective water shut off system to provide a cost effective

solution for water shut off4. The potential to use selective water shut off to treat wells where there is a high

degree of uncertainty and so no other option for water shut off5. The potential to design an initial treatment to manage risk in such cases6. The potential to learn from initial outcomes and improve treatment performance on

repeat applications.

Acknowledgements

The authors would like to thank the Miller asset for permission to publish this paper, as well as Majid Alane for performing (lots of) sandpack tests.

References

1. Morgan J., Gunn A., Fitch G., Frampton H., Harvey R., Thrasher D., Lane R., McClure R., Heier K.H. and Kayser C. Development 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

2. Wylde J.J, Williams G.D.M., Careil F., Webb P., and Morris A. Deep downhole chemical injection on BP operated Miller: Experience and learning. To be presented at Reservoir Simulation Symposium 2005 Texas USA

3. Wylde J.J. Williams G.D.M., Careil F., Webb P. and Morris A. A new type of super-adsorption high-desorbtion scale squeeze chemistry: doubling treatment life on Miller Wells. To be presented at the SPE 2005 Scale Conference, Aberdeen.

4. Wylde, J.J. SPE, Williams, G.D.M SPE and Careil, F Innovative, Integrated and cost effective chemical management on the Miller Platform. To be presented at the Middle East Oil and Gas Show and Conference 2005

5. Wylde, J.J., Williams G.D.M., Wiliams G.D., Frampton H. and Morgan J. A Chemical Solution to Increasing Oil Production Whilst Minimising Water Production Using Polymeric Water Shut Off Gels. EAGE 13th Euro. Symp. On Improved Oil Recovery, Budapest, Hungary, 25-27 April 2005.

Figure 1. Modes of operation of different types of gel system. Top: rigid, impermeable gels fill the pore spaces and prevents flow of any fluid. Middle: RPM polymer systems form a surface coating on the formation. In high permeabilities fluids can flow unhindered through the middle of

the pore throats. Bottom: Selectively permeable gel fills the pore space but still allows fluid to migrate through.

10003 hours of scale

inhibitor flow at 3ml/h.Oil backflow

started at 3ml/h

----- 0-1 ft into sandpack

— 1-2.5 ft into sandpack

SSW backflow resumed at 3ml/h

SSW backflow at 3ml/h

SSW backflow resumed at 3ml/h

Time / days

Figure 2. Graph showing the resistance to brine flow caused by the gel during post-treatment flowback through a 5' long sandpack treated with the chemical package used for the first treatment on A18. Permeability was 600mD, and the pack was conditioned with brine and crude to residual oil saturation prior to injection of the treatment. The effect of the gel is expressed as the ratio of pre- to post-treatment permeability (i.e. RFW 100 = 99% reduction in permeability, RFW 200 = 99.5% reduction and so on). The graph plots the observed reduction in effective permeability of the pack as a function of time. These data illustrated i) a reduction in permeability to brine of over 99% caused by the treatment, with the greatest effect seen in the first section (i.e. the near wellbore); ii) stability of the system with regard to scale inhibitor returns; hi) rapid dehydration and reduction in resistance when oil is flowed through the pack; iv) the ability of the system to rehydrate and provide continued resistance to water after there has been oil flow.