EP1257727A1

EP1257727A1 - Method of treating reservoir zone of hydrocarbon producing well to inhibit water production problems

Info

Publication number: EP1257727A1
Application number: EP01951158A
Authority: EP
Inventors: Rex Man Shing Wat; Hans Kristian Kotlar
Original assignee: Statoil ASA; Champion Technologies Inc
Current assignee: Equinor ASA; Champion Technologies Inc
Priority date: 2000-02-11
Filing date: 2001-02-07
Publication date: 2002-11-20
Also published as: PE20011017A1; GB0003214D0; EG23023A; BR0108245A; WO2001059255A1; NO20023772L; AU7206001A; NO20023772D0; AR027408A1; GB2359104A; US20030155123A1

Abstract

A method of treating an oil well to inhibit scale formation. An oil soluble scale inhibitor is injected into the well during the completion phase. The inhibitor hydrolyses on contact with connate water in the well and the active part enters the water phase. It remains in the water phase while oil is extracted and until the water breaks through. At that stage, the inhibitor becomes active in inhibiting scale formation.

Description

Method of Treating Reservoir Zone of Hydrocarbon Producing Well to Inhibit Water Production Problems

The present invention is concerned with a method of treating a reservoir zone of a hydrocarbon producing well to inhibit problems associated with water production. It is particularly but not exclusively applicable to a preventive scale treatment in oil, gas and condensate fields, using an oil soluble scale inhibitor (OSI).

An increasing number of complex and expensive wells are being installed, e.g. multilateral, multi- zones, sidetrack and horizontal completions.

The infrastructures which are in place, such as flow lines and platforms, also enable us to target and drain the additional reserves found near the exiting fields. Very often these additional oil and/or gas are produced via tieback and satellite facilities. Successful scale squeeze treatments in these wells can no longer rely on the traditional method of bullheading the chemicals into the reservoir. Special tools such as coil tubing will be needed to place the chemicals accurately. ' Intervention in these wells will be prohibitively expensive due to tools hire, personnel and extended period of deferred oil production. It is important to realise that for certain types of completions, well re-entry is almost impossible despite accepting the financial penalty. There is clearly a need to develop the systems with as low an intervention frequency as possible for these wells, i.e. with the chemicals pre-delivered downhole.

Preventive rather than remedial treatments against scale, hydrate and other tubing deposits represent the first step towards achieving such goal. For example, in the case of scale inhibition, preventive treatment means the delivery and deposition downhole of an appropriate scale inhibitor package at an early stage, i.e. before the well starts producing scaling water. A number of options on scale preventive treatment have emerged recently. These include water soluble scale inhibitors, proppant/ gravel pack based solid scale inhibitors, oil soluble scale inhibitors (OSI), emulsified scale inhibitors and micro particle systems for deep matrix placement. Traditionally, scale deposition has been considered to be a water related problem, i.e. if no water is produced no scale forms. As such, almost all scale inhibitor chemicals are water soluble and are typically deployed as an aqueous based product. For preventive treatment in a 'dry' or 'modestly dry' well, the use of a conventional water based scale inhibitor may cause a significant, though usually temporary, reduction in its productivity. One of the main concerns and a frequently observed problem when carrying out a water based squeeze is the length of the necessary clean up period. It is often found that the well might take weeks or months to regain its pre-squeezed level of oil production. In most cases, the loss of oil production is the direct result of a decrease in the oil relative permeability caused by the change in water saturation near the wellbore region which creates emulsions. These problems are not experienced with oil soluble squeezes. How-' fast the well can recover will depend on the wettability of the rock which is a specific property for a given crude/produced brine/formation matrix system. For those wells with weak bottom hole pressure and/or a lack of artificial lift, the excessive water injected during the squeeze treatment will pose a risk of killing the well. The ingress of water means a much higher draw down is needed to induce the well to flow back.

The lost or deferred oil production is often based on the well shut-in time during the squeeze treatment. This can be misleading especially if the well requires a significant clean up period to regain its pre-squeeze level of oil production. Together with the other commonly observed problems when using a water base scale inhibitor, e.g. process upset and poor water quality (discharged), operato-s are often reluctant to be proactive. As a result the squeeze treatment is usually postponed to avoid upsetting the oil production and is only carried out when the production decline starts, i.e. after damage has been done.

It is an object of the present invention to provide a method of treating a hydrocarbon producing well to prevent scale deposition and build up which does not suffer from these various drawbacks.

According to the invention, there is provided a method of treating a reservoir zone of a hydrocarbon producing well during the completion phase to inhibit problems associated with water production, the method comprising: deploying into the near wellbore region of a reservoir zone during the completion phase a hydrocarbon-compatible treatment agent in a hydrocarbon phase; allowing the active component of the treatment agent to enter irreversibly the connate water in the well region; and allowing the active component to be retained by the rock matrix in the well region, whereby the active component of the treatment agent actively inhibits the respective problem if and when water is finally produced from the reservoir zone.

The hydrocarbon well may be for example an oil well or a gas well. The problems associated with water production include corrosion and hydrate formation, and in particular, scale formation. The term "hyrocarbon- compatible" includes materials which are transportable in or can be carried by a hydrocarbon phase, and particularly includes oil soluble materials. Preferably, therefore, the treatment agent is an oil-soluble scale inhibitor. The entry of the active component into the connate water phase is irreversible and this may be achieved by any convenient mechanism. Thus water soluble treatment agents can be made hydrocarbon-compatible by means of a surfactant package such as a surfactant-micelle system or by means of an emulsion. Preferably, however, the treatment agent is an oil soluble material which hydrolyses or decouples on contact with water.

The term "completion phase", when applied to reservoir zones of hydrocarbon wells, means essentially, the stage before the well is put into planned long term production from that zone or the stage before the well is intended to produce uninterruptedly for a significant period of time.

In the event that it is decided to divide a well into a plurality of reservoir zones, one may decide to complete one zone, produce that zone for some time, and later start production from a different zone. The already producing zone may or may not be closed for production. The process of opening a new zone for production is often referred to at recompletion of the well. For the purpose of this application therefore, the term "completion phase" covers the stage of opening and preparing for production a previously not produced zone, also in the case that the well already has produced from one or more different zones.

The treatment agent remains in the connate water or is adsorbed on to the mineral surface of the reservoir. The system allows free production of hydrocarbons without eluting any of the treatment agent during pure hydrocarbon production then when water breaks through, the treatment agent will be released in adequate concentrations for protection against scaling.

Preferably, the treatment agent is deployed at the end of the completion phase of the well developed. However, the treatment agent can also be deployed at any time during the completion phase.

Preferably, the treatment agent is an oil soluble scale inhibitor or combinations of oil soluble scale inhibitors, including different soluble inhibitors. Suitable materials can be obtained from Champion Technologies. Products are available which make use of different molecules and active concentrations. Such combinations may take advantage of different absorption isotherms of various inhibitors, playing on both short term and long term dissolution or desorption from the matrix. This could also be combined with mixing of different generic types of inhibitors and also mixing in such a way that for example inhibitors most efficient in protection of carbonate scale could be combined with inhibitors most efficient in protection of sulphate scale. Likewise, combinations of scale, corrosion and hydrate inhibitors could be employed during the same squeeze, or in sequence of the same squeeze to obtain multiple protection. There are clear advantages in using an oil soluble scale inhibitor (OSI), particularly when used in wells during the completion phase and in low energy reservoirs. These exploit the hydrodynamic differences between an oleic and an aqueous phase. To be deployed successfully in the field as a preventive treatment against scale, the OSI preferably behaves like a conventional water based product as and where it is needed. This requires the active agent of the

OSΪ to be present in the produced water when the well starts cutting water, which can be some months or years after it was first deployed. For this reason the OSI package preferably possess properties which enable it to deliver selectively the desired component(s). These properties include a ready transfer process from the oil (carrier) phase into the water phase when in contact. The mass transfer process, including hydrolysis and partitioning of the molecules, is preferably rapid. The hydrolysed molecules, after partitioning in the water phase, must then be able to inhibit scale formation. Furthermore, in order to yield a long squeeze life, the partitioned molecules are preferably strongly adsorbed by the rock matrix.

Preferably, the hydrolysis is an irreversible process and preferably, the hydrolysis renders the treatment agent water soluble. The partition between the hydrocarbon and connate water phases may be followed by or be a consequence of the hydrolysis and both operations may be controlled.

The treatment agent is preferably an oil-soluble penta phosphate derivative which hydrolyses to a penta phosphonate according to the reaction :-

[X-O r- PO

(X O)₂-

(X-0)₂-

(HO)₂-PO

Preferably, the concentration of the treatment agent in the connate water is higher than the concentration in the hydrocarbon phase as a result of the hydrolysis and the subsequent irreversible mass transfer between phases.

Preferably the concentration of the treatment agent in the hydrocarbon material as delivered to the formation is >2wt%, more preferably 2 to 30 wt%. Preferably, the concentration of the treatment agent in the hydrocarbon material after delivery to the formation is </wt%. Preferably, the concentration of the treatment agent in the connate water after delivery of the hydrocarbon material carrying the treatment agent is >2wt% more preferably 2 to 50 wt%. The hydrocarbon phase in which the treatment agent is deployed may be any suitable hydrocarbon material, for example, kerosene, lamp oil, diesel oil, crude oil, condensate, synthetic oils etc. Preferably, the connate water concentration of the treatment chemical is supporting a concenti ation driven adsorption. Preferably, the adsoφtion to the matrix from the connate water continues even after the hydrocarbon production is stared, giving a shut-in time requirement only for the oil to water process to take place. In the case of partitioning, the shut-in and hydrolysis for most temperatures may have reached termination at 30 minutes.

Preferably, the OSI will give reduced initial flow-back return of the treatment agent and will be environmentally friendly. Conveniently, it will offer protection time in early and/or unexpected water break through. The OSI can be employed with/or without a preflush, which may consist of a mutual solvent and/or surfactants or other additives. The OSI can be employed also in wet wells with an appropriately sized hydrocarbon preflush to render the water saturation in the treatment region as low as possible.

The OSI chemicals may be truly oil solublised without the addition of any mutual solvent, surfactants or other additives. It is believed that the OSI chemical and treatment procedure will not give adverse relative permeability effects. It can be administrated with or without coil tubing and will be able to withstand significant thermal degradation for a defined period of time.

The present invention can therefore offer the following benefits: a preventative treatment incoφorated in a well completion programme; more efficient chemical usage; increased environmental friendliness, with a minimum or no return of treatment chemicals if the well is dry, (since the chemicals will remain in the connate water); no high peak in flow-back return; reduced shut-in time; protection in the case of early/unexpected water break-through; reducing initial scaling; reduced sand production and clay swelling which would normally be expected within a water injection; savings on subsequent costly treatments and interventions related to damage and repair of equipment; and start-up problems are minimised. The invention may be carried into practice in various ways and some embodiments will now be illustrated in the following examples and experiments and described with reference to the accompanying drawings in which:-

Figure 1 is a graph showing the partitioning of OSI in oil and water phases:

Figure 2 is a schematic view of the reservoir P-MAC apparatus;

Figure 3 is a graph showing the effect of scaling on the pressure drop along the P-MAC coil;

Figure 4 is a graph showing the results of a preventive squeeze with OSI; and

Figures 5 to 10 are graphs representing the results in various experiments.

When sea water (SW) and formation water (FW) mix, scaling can occur immediately. Thus, the salts in each of the solutions of SW and FW are soluble, but when mixed, some ions form each solution may form salts that are not soluble.

The tests of the Sale inhibitors were carried out by pretreating a sandpack column in various ways to simulate a squeezed reservoir, and then flow the SW through the column. As some oil will be produced before the SW has flowed through, the clock is started when the mix of FW and SW is seen at PI.

The comparative tests (no Scale inhibitor) described below were carried out by by-passing the sandpack column, i.e. a stream of SW and FW is mixed, and enters the coil. The time is taken from when the mix of SW and FW is seen at PI, until there is enough scale in the coil that a pre-determined pressure difference is observed between PI and P2.

A set up such as this is necessary, in order to put the preventative chemical into a stream at a stage before any scale is produced, and it is known that scaling conditions will occur at a later stage.

Chapter 1 Field Tests

Some experiments have been carried out under field conditions. Several squeeze treatments using suitable OSI products have been conducted for example in the North Sea. These are not in accordance with the invention since the wells treated were already producing water.

For the treatments carried out in the North Sea, the reservoir temperatures varied between 110°C to 125°C and the water cuts varied between 1% to 20% . Both diesel and base oil were used as the carrier fluid. The general observations during the flow back period can be summarised as follows.

Injectivity was unchanged with WHP remaining high during injection. Clean up is not an issue, in that the wells flow back instantly with an unchanged water/oil cut. Topside process suffered no apparent upset, as often observed with water based squeeze (caused by the return of large volume, high concentration scale inhibitor). As for discharge, no apparent oil-in-water problems were encountered as have often been observed with water based squeezes.

Chapter 2 Partitioning of Oil Solub le Scale Inhibitor In order to study the partitioning of the OSI between the oil and water phases the following laboratory experiment was conducted.

In this test, a 10% OSI solution was made up in crude oil. The sample was then mixed with Statfjord formation water (FW) at 5:1 ratio (cf. 17% S_wi).

The mixture was shaken briefly and left in an oven overnight at 80°C. The aqueous and the oleic phases were separated in the following day. Together with an original sample (10% in crude) they were analysed using Fourier

Transform Infrared Spectrometry (FTIR) which offers a quick and qualitative response. It is particular useful for the phosphonate based OSI since the P=0 and P-OH) bonds (stretching vibrations) can be easily identified at the wave numbers of -1150 and -970 respectively. It is clear from Figure 1 that upon contact with water, most of the OSI molecules are transferred from the oil phase into the aqueous phase through a combined hydrolysis and partitioning process.

The mass transfer process was achieved very rapidly and the level of transfer was extremely high with little (<0.1%) or no OSI detected in the final oil layer. In contrast, due to the small amount of water present, the final scale inhibitor concentration in the aqueous phase was significantly higher than that in the original OSI mix. Such 'ENHANCED PARTITIONING' will have strong implication in the deployment strategy and utilisation efficiency of the product in the field.

Pressure Monitoring and Control (P-MAC) One piece of equipment which can be used for OSI testing is the Reservoir

P-MAC (Pressure Monitoring And Control) as shown in Figure 2. It is based on standard tube blocking apparatus with the addition of a pre-column. In this setup, a sandpack is inserted into a sea water line and placed upstream of the P-MAC coil. The puφose of this column is to enable a simulated squeeze treatment using OSI to be carried out prior to any test. When the co-injection of the incompatible brine starts, the sea water would elute the adsorbed scale inhibitor. As a result, there would be a time delay for the coil to scale up to the pre-set pressure (ΔP = 1 Bar). Comparison could then be made with the "blank" run in which no prior squeeze treatment had been carried out in the column.

Chapter 3 Effect of Hydrocarbon P roduction on Partitioned OSI

This test was conducted using the P-MAC apparatus. In this test, two separate runs were carried ou with a sandpack column pre-treated (squeezed) with OSI. In the first run, sea ater was directly injected and the delay in the scale up time was observed. In the second run a volume (50 ml) of kerosene was injected prior to the sea water, i.e. to simulate oil production in a dry well until the first water breaks through. The objective of this was to examine if the adsorbed OSI molecules could be removed readily by the passage of hydrocarbon. The results show that the flow of hydrocarbon did not displace the inhibitor and that the presence of the inhibitor delays scaling up the coil, as can be seen from figure 3. The time of scaling up the coil is measured form the time when formation water and sea water mix.

Chapter 4 Preventive Squeeze Study

Figure 4 shows an experiment where the OSI was squeezed into a sand pack with subsequent back production of sea water and formation water (curve labelled SA1070(10%)). This gave a protection time in this system of about 23 minutes, or about 20 pore volumes (PV). The same type of squeeze was carried out before the sand pack was back produced with sea water and formation water, it was back produced with 6 PV of the hydrocarbon phase. This was carried out at two different inhibitor concentrations (curves, SA 1070(10%) +

6PV-CH and SA1070(2%) + 6PV-CH, respectively). Protection time is just in the same range as when only brine was back produced. This indicates that no OSI is being removed by the hydrocarbon phase. The inhibitor will therefore reside in the connate water or on the formation rock until formation water or sea water is produced. Experimental Details

Details of the sand packs used are as follows. Sand packs

Omni columns with inner diameter 15mm (minus end pieces), packed with Baskaφsand, were used in the experiments. The column was made of borosilicate glass, and the frits of each end piece were porous discs of polyethylene with pore size 25 μm.

The particle size distribution of the Baskaφsand is given in Table 1. Chemical analysis of the sand is given in Table 2. Table 1. Particle size distribution of Baskarpsand.

Table 2. Chemical analysis of Baskarpsand

Brines

The compositions of the sea water and formation water used in the blocking tests are given in Tables 3 and 4. The composition of the formation of water is taken as an average of more general formation waters, but with an increased concentration of Barium (400ppm Ba²⁺). This is to service two puφoses. a) The precipitation in the P-mac coil will occur within reasonable time and repeatable manner. b) In order to resemble Heirun formation water; Barium concentration in Heidrun Fangst is around 190ppm, while Heidrun Are is reported with values from 100 to 350ppm (A-22 FW) and also as high as 800ppm. Thus, a formation water with 400ppm of Barium was chosen.

Table 3 Composition of synthetic sea water

Table 4. Composition of synthetic formation water

Inhibitors

Both the oil soluble inhibitor used in the experiments are pentaphosphonates delivered from Champion Technologies. The commercial name of the oil soluble inhibitor is SA1070. The commercial name of the water soluble inhibitor is SA1130. These inhibitors will correspond to traditionally DETA pentaphosphonate (DTMP).

Column packing and preparations Frits and o-rings were checked eventually changed and one end piece was mounted on the column. About 37g Baskaφsand was poured into the column while vibrating it over a period of 1 / min. The batch of sand was kept in an oven at 80°C. The other end piece (adjustable) was mounted and the column was weighed. The column was evacuated by means of a vacuum pump (vertical position) and filled with distilled water with the vacuum pump still on. The water permeability over the column was found by measuring the differential pressure over the column at different rates (100,200, 300, 400 and 400 ml/h). The column was weighed at 100% water saturation and the length of the sand pack was measured. The dead volume in tubes and end pieces was found by weighing an empty column with and without water and the volume of the empty cylinder was subtracted from this difference.

To make the sand in the columns oil wet, 50 ml Heidrun A46 crude was pumped through the column at a rate of 400 ml/h. This operation was done at 70°C. Before the inhibitor squeeze the column was kept in the oven at 90°C for three days.

Table 5 and Table 6 give the column data for the different experiments.

Table 6 Column data for the experiments with water soluble scale inhibitor

Oil soluble inhibitor squeeze The following operations were carried out at 90°C. At startup, the column was 100% saturated with water.

1. 50 ml kerosene was pumped through the column at 400 ml h. The water volume that come out was measured and the residual water saturation calculated on the basis of this. 2. A given volume of inhibitor diluted in kerosene was pumped through the column at 400 ml/h. (Inhibitor concentrations in the kerosene are given in Table 4.2).

3. The column was left at 90°C over night.

Table 7 gives the amount of water that came out of the column during the injection of kerosene, and the calculated residual water saturation before the inhibitor injection.

Table 7 Residual water saturation before the inhibitor squeeze

Table 8 P-mac results for the tests with oil soluble inhibitor

Water soluble inhibitor squeeze

100 ml of 4 wt% SA1130 in sea water was pumped through the column at 400 ml/h at room temperature before the column was left at 90°C over night.

Table 9 P-mac results for the tests with water soluble inhibitor.

Trial Inhibitorconc. in Inhibitorvolum Tune to 1 bar ref. T me to 1 bar with sea water in squeeze only SW+FW treated column

WSI 1 4% 100 ml 11 min. 12 min.

WSI 3 4% 100 ml 8 min. 12 min.

Reservoir P-mac Operative Conditions

The compositions of the sea water and formation water used in the experiments are given in Tables 3 and 4. A general composition formation water with

400ppm Ba -21- was used. The brines were degassed before every experiment. The column, and capillary tube were both placed in water baths at 90°C. The two waters were therefore preheated before they were mixed.

Before every experiment a reference experiment without inhibitor (the blank) was carried out. For the experiments with oil soluble scale inhibitor, 50 ml kerosene was pumped through the column in the opposite direction of the inhibitor injection at 400 ml/h. The column was then placed in the sea water line of the P-MAC, with the same flow direction as for kerosene. Some formation water was first flowed through the capillary tubing to ensure that the differential pressure measurement and the printer were working normal before the sea water pump was started. During the experiment, 400 ml/h of both formation water and sea water were pumped through the capillary tubing until the differential pressure over the capillary tube reached 1000 mbar.

After each experiment, the capillary tubing was rinsed with a 10% scale dissolver solution in distilled water. The rinsing fluid was pumped through the tube in the opposite flow direction for 20 minutes at a rate of 499 ml h.

Ageing

To test the temperature stability of the inhibitor over time, two squeezed columns were kept at 165°C over an extended time period before they were tested in the P-MAC. The polyethylene frits were replaced with a piece of woven steel because of the high temperature.

The columns were packed, pre treated and squeezed as normal. Caps, fittings and tubes were removed from the columns. The open columns were placed in a piston bottle filled with kerosene on one side of the piston (the side with the columns) and empty on the other side. The piston bottle was placed in an oven and the empty side was connected to a N₂ — pressure of 15 bar. The oven was heated to 155°C and the pressure then rose to about 20 bar. The columns were left in the oven for 15 and 136 days, respectively. The heat was turned off and the pressure was reduced and tubes were mounted on the column. The columns were post flushed with 50 ml kerosene before they were tested in the reservoir P-MAC as described above. The results of the various further experiments are summarised in Figures 5 to 10, which show the differential pressure over the capillary tubing during the period of the blocking tests. An average of the results of the reference tests without inhibitor is shown in each Figure. The experimental conditions are given in Tables 8 and 9. A squeeze with the water soluble version of the OSI was tested first in order to estimate the expected protection time of the squeeze. The results are shown in Figure 5. Different concentrations were tested. Also thermal stability of the OSI is crucial for long term activity. Although certain reservoir temperatures will only vary between 85-98°C, the ageing was carried out at 165°C to accelerate the degradation process.

Figure 6 shows oil soluble inhibitor squeeze with different concentrations and ageing. It shows that the protection time of the oil soluble inhibitor squeeze is in the same range for different inhibitor concentrations in kerosene (2-10%). Note that this is when pumping 100 ml of inhibitor solution through the column. Ageing of the squeezed column at 165°C for 15 days does not seem to reduce the efficiency of the inhibitor. When comparing Figures 5 and 6, there are indications that the protection time of the experiments with an oil soluble inhibitor squeeze is almost double that when a water soluble inhibitor was used. Figure 7 shows the result of two P-MAC tests with no shut-in time.

Compared with Figure 6 it appears that shut-in time had beneficial effect on the oil soluble inhibitor treatment. However, results from the partitioning experiments combined with reservoir P-MAC experiments indicate that there is no benefit from shut-in times longer than 3 hours.

Figure 8 shows the results from two P-MAC tests with oil wet sand. The oil wet columns had the longest inhibitor treatment lifetime of all the experiments. The reason for this may be that the oil wet columns had a lower initial water saturation than the other columns (see Table 8).

In an attempt to optimise the squeeze procedures and to investigate the mechanisms of the OSI, different squeeze methods were tested. In one test, a column with much higher water saturation was achieved by lowering the drainage velocity.

Figures 9 and 10 show the results from P-MAC experiments with different squeeze procedures. In all three cases, the same amount of inhibitor was squeezed into the column, but in different ways. The first column was filled with one pore volume of 3.3% inhibitor in kerosene without overflush. The second column was filled with 1/3 pore volume with 10% inhibitor in kerosene followed by 2/3 pore volume of kerosene to displace the inhibitor. These three tests were conducted both with 15cm long columns (Figure 10) and 25 cm long columns (Figure 9). The experiments gave no clear differences between the three squeeze methods. Figure 10 also shows the treatment lifetime for a squeeze with one pore volume of 3.3% SA1070 in kerosene on a column with 33% water saturation. The water saturation of the other columns varies between 16-26% (see Table 8).

The conclusions to be drawn from the experiments and tests can be summarised as follows: The scale protection time of the oil soluble inhibitor treatment has been compared with the lifetime of a squeeze with the corresponding water soluble chemical. The lifetime of the experiments with oil soluble inhibitor squeeze was almost double of the protection time of experiments with water soluble inhibitor. Experiments with varying inhibitor concentration in kerosene showed that in the concentration range of 2-10 wt %, the protection time of the oil soluble inhibitor was in the same range for all the inhibitor concentrations in kerosene. This indicates that at 2 wt % one approaches the concentration limit of the corresponding connate water. In these experiments SWI is varying between 22-26%.

Ageing of the squeezed column at 165°C for 15 days does not seem to reduce the effectiveness of the inhibitor. However, after 4 or 5 months ( 136) days, the protection time is reduced to 50% of the initial. Applying the

Arrhenius relations, indicating that the rate of reaction doubles for each 10°C increase, and knowing the temperature at the Heidrun field to be much lower, the expected protection time will be considerably longer.

Two experiments were performed with no shut-in time. The results indicate that shut-in time gives an enhanced lifetime to the oil soluble inhibitor treatment. This implies that the hydrolysis and the absoφtion with the concentration driven mechanism need some time. These experiments were performed with 22 hours shut-in time. However other mechanistic studies indicate a shut-in of 3 hours should be more than sufficient in practice. Two experiments were performed with columns filled with oil wet sand.

These had the longest inhibitor treatment lifetime of all the experiments. These again point to a concentration driven absoφtion mechanism. The connate water will only obtain a certain saturation concentration, thus, driving/forcing the absoφtion of the inhibitor to the matrix. In order to investigate the sequence of the squeeze procedure, two series of three P-MAC experiments were performed where the same amount of inhibitor was squeezed into the columns in three different ways. The experiments gave some indications, but no clear differences between the different squeeze methods.

The experiments clearly suggest that a preventive squeeze treatment is achievable. This means that the inhibitor will be retained in the near wellbore area until the formation water is produced.

Claims

1. A method of treating a reservoir zone of a hydrocarbon producing well during the completion phase to inhibit problems associated with water production, the method comprising: deploying into the near wellbore region of a reservoir zone during the completion phase a hydrocarbon-compatible treatment agent in a hydrocarbon phase; allowing the active component of the treatment agent to enter irreversibly the connate water in the well region; and allowing the active component to be retained by the rock matrix in the well region, whereby the active component of the treatment agent actively inhibits the respective problem if and when water is finally produced from the reservoir zone.

2. A method as claimed in Claim 1, in which the treatment agent is a hydrocarbon soluble material, a surfactant-micelle system or an emulsion.

3. A method as claimed in Claim 2, in which the active component is one which hydrolyses on contact with water.

4. A method as claimed in Claim 3, in which the hydrolysis is an irreversible process.

5. A method as claimed in any preceding Claim, in which the hydrolysis renders the treatment agent water soluble.

6. A method as claimed in any preceding Claim, in which the treatment agent is deployed at the end of the completion programme.

7. A method as claimed in any preceding Claim, in which the treatment agent is an oil soluble scale inhibitor or a combination of oil soluble scale inhibitors.

8. A method as claimed in any preceding Claim, in which the concentration of the treatment agent in the water phase is higher than the concentration in the hydrocarbon phase as a result of the irreversible mass transfer between phases.

9. A method as claimed in any preceding Claim, in which the concentration of the treatment agent in the hydrocarbon material as delivered to the formation is >2 wt%.

10. A method as claimed in any preceding Claim, in which the concentration of the treatment agent in the hydrocarbon material after delivery to the formation is <1 wt%.

11. A method as claimed in any preceding Claim, in which the concentration of the treatment agent in the connate water after delivery of the hydrocarbon material carrying the treatment agent is >2 wt%.

12. A method as claimed in any preceding Claim, in which the hydrocarbon phase is selected from kerosene, lamp oil, diesel oil and crude oil.