US20030155123A1 - Method of treating reservoir zone of hydrocarbon producing well to inhibit water production problerms - Google Patents

Method of treating reservoir zone of hydrocarbon producing well to inhibit water production problerms Download PDF

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Publication number
US20030155123A1
US20030155123A1 US10/203,171 US20317102A US2003155123A1 US 20030155123 A1 US20030155123 A1 US 20030155123A1 US 20317102 A US20317102 A US 20317102A US 2003155123 A1 US2003155123 A1 US 2003155123A1
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Prior art keywords
water
treatment agent
hydrocarbon
osi
oil
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US10/203,171
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English (en)
Inventor
Rex Wat
Hans Kotlar
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Statoil ASA
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Assigned to STATOIL ASA reassignment STATOIL ASA ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: KOTLAR, HANS KRISTIAN, WAT, REX MAN SHING
Publication of US20030155123A1 publication Critical patent/US20030155123A1/en
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    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/502—Oil-based compositions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B37/00—Methods or apparatus for cleaning boreholes or wells
    • E21B37/06—Methods or apparatus for cleaning boreholes or wells using chemical means for preventing, limiting or eliminating the deposition of paraffins or like substances

Definitions

  • 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).
  • OSI oil soluble scale inhibitor
  • 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.
  • scale preventive treatment 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.
  • OSI oil soluble scale inhibitors
  • a method of treating a reservoir zone of a hydrocarbon producing well during the completion phase to inhibit problems associated with water production 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.
  • the treatment agent is an oil-soluble scale inhibitor.
  • 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.
  • the treatment agent is an oil soluble material which hydrolyses or decouples on contact with water.
  • 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.
  • 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.
  • the treatment agent is deployed at the end of the completion phase of the well developed.
  • the treatment agent can also be deployed at any time during the completion phase.
  • 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.
  • 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.
  • OSI oil soluble scale inhibitor
  • the OSI preferably behaves like a conventional water based product as and where it is needed. This requires the active agent of the OSI 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.
  • the partitioned molecules are preferably strongly adsorbed by the rock matrix.
  • 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:
  • 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.
  • the concentration of the treatment agent in the hydrocarbon material as delivered to the formation is >2 wt %, more preferably 2 to 30 wt %.
  • the concentration of the treatment agent in the hydrocarbon material after delivery to the formation is ⁇ /wt %.
  • the concentration of the treatment agent in the connate water after delivery of the hydrocarbon material carrying the treatment agent is >2 wt % 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.
  • the connate water concentration of the treatment chemical is supporting a concentration driven adsorption.
  • the adsorption 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.
  • 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 incorporated 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.
  • FIG. 1 is a graph showing the partitioning of OSI in oil and water phases:
  • FIG. 2 is a schematic view of the reservoir P-MAC apparatus
  • FIG. 3 is a graph showing the effect of scaling on the pressure drop along the P-MAC coil
  • FIG. 4 is a graph showing the results of a preventive squeeze with OSI.
  • FIGS. 5 to 10 are graphs representing the results in various experiments.
  • 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.
  • This test was conducted using the P-MAC apparatus. In this test, two separate runs were carried out with a sandpack column pre-treated (squeezed) with OSI. In the first run, sea water 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 FIG. 3. The time of scaling up the coil is measured form the time when formation water and sea water mix.
  • FIG. 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, SA1070(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.
  • 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 (400 ppm Ba 2+ ). This is to service two purposes.
  • 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).
  • Frits and o-rings were checked eventually changed and one end piece was mounted on the column.
  • About 37 g Baskarpsand was poured into the column while vibrating it over a period of 11 ⁇ 2 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.
  • 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 Water out Water left Water saturation Trial [ml] [ml] [%] OSI 2 6.8 2 26 OSI 3 7.0 1.6 22 OSI 5 7.1 1.3 18 OSI 6 7.0 1.8 24 OSI 7 7.0 1.6 22 OSI 8 6.0 2.4 33 OSI 9 7.5 1.2 16 OSI 10 11.6 2.4 18 OSI 11 11.8 2.9 21 OSI 12 11.5 3 23 OSI 13 7.1 1.1 16 OSI 14 7.2 1.3 18 OSI 15 6.4 1.8 24 OSI 16 6.7 1.5 20 OSI 17 7.0 1.3 18
  • 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 400 ppm Ba 2+ 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.
  • 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.
  • FIGS. 5 to 10 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 FIG. 5.
  • FIG. 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 FIGS. 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.
  • FIG. 7 shows the result of two P-MAC tests with no shut-in time. Compared with FIG. 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.
  • FIG. 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).
  • FIGS. 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 15 cm long columns (FIG. 10) and 25 cm long columns (FIG. 9). The experiments gave no clear differences between the three squeeze methods.
  • FIG. 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).
  • shut-in time gives an enhanced lifetime to the oil soluble inhibitor treatment. This implies that the hydrolysis and the absorption 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.
US10/203,171 2000-02-11 2001-02-07 Method of treating reservoir zone of hydrocarbon producing well to inhibit water production problerms Abandoned US20030155123A1 (en)

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GB0003214.4 2000-02-11
GB0003214A GB2359104A (en) 2000-02-11 2000-02-11 Method of treating hydrocarbon well to inhibit water production problems

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US (1) US20030155123A1 (fr)
EP (1) EP1257727A1 (fr)
AR (1) AR027408A1 (fr)
AU (1) AU7206001A (fr)
BR (1) BR0108245A (fr)
EG (1) EG23023A (fr)
GB (1) GB2359104A (fr)
NO (1) NO20023772L (fr)
PE (1) PE20011017A1 (fr)
WO (1) WO2001059255A1 (fr)

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20050072570A1 (en) * 2003-10-06 2005-04-07 Lehman Lyle Vaughan Contamination-resistant sand control apparatus and method for preventing contamination of sand control devices
US20050139356A1 (en) * 2003-12-31 2005-06-30 Chevron U.S.A. Inc. Method for enhancing the retention efficiency of treatment chemicals in subterranean formations
US20240084675A1 (en) * 2022-09-14 2024-03-14 China University Of Petroleum (East China) Apparatus for preventing and controlling secondary generation of hydrates in wellbore during depressurization exploitation of offshore natural gas hydrates and prevention and control method

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6913081B2 (en) 2003-02-06 2005-07-05 Baker Hughes Incorporated Combined scale inhibitor and water control treatments

Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6379612B1 (en) * 1998-07-27 2002-04-30 Champion Technologies, Inc. Scale inhibitors

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US3832302A (en) * 1972-01-17 1974-08-27 Halliburton Co Methods for inhibiting scale formation
US3799265A (en) * 1973-01-15 1974-03-26 Marathon Oil Co Use of micellar solution as an emulsion breaker
US4518511A (en) * 1979-11-21 1985-05-21 American Cyanamid Company Delivery of polymeric antiprecipitants in oil wells employing an oil soluble carrier system
US4602683A (en) * 1984-06-29 1986-07-29 Atlantic Richfield Company Method of inhibiting scale in wells
EP0447120B1 (fr) * 1990-03-14 1995-05-24 Mobil Oil Corporation Méthode à membrane liquide pour la dissolution catalytique du tartre
GB9510563D0 (en) * 1995-05-24 1995-07-19 Atomic Energy Authority Uk Well inhibition
US5853619A (en) * 1996-11-22 1998-12-29 Nalco/Exxon Energy Chemicals, L.P. Low toxic corrosion inhibitor
CA2277681A1 (fr) * 1998-07-27 2000-01-27 Champion Technologies, Inc. Element anti-incrustant

Patent Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6379612B1 (en) * 1998-07-27 2002-04-30 Champion Technologies, Inc. Scale inhibitors

Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20050072570A1 (en) * 2003-10-06 2005-04-07 Lehman Lyle Vaughan Contamination-resistant sand control apparatus and method for preventing contamination of sand control devices
WO2005035938A1 (fr) * 2003-10-06 2005-04-21 Halliburton Energy Services, Inc. Appareil de controle du sable resistant a la contamination et procede destine a empecher la contamination de dispositifs de controle du sable
US20050139356A1 (en) * 2003-12-31 2005-06-30 Chevron U.S.A. Inc. Method for enhancing the retention efficiency of treatment chemicals in subterranean formations
US7021378B2 (en) 2003-12-31 2006-04-04 Chevron U.S.A. Method for enhancing the retention efficiency of treatment chemicals in subterranean formations
US20240084675A1 (en) * 2022-09-14 2024-03-14 China University Of Petroleum (East China) Apparatus for preventing and controlling secondary generation of hydrates in wellbore during depressurization exploitation of offshore natural gas hydrates and prevention and control method

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NO20023772D0 (no) 2002-08-09
WO2001059255A1 (fr) 2001-08-16
GB0003214D0 (en) 2000-04-05
AU7206001A (en) 2001-08-20
EP1257727A1 (fr) 2002-11-20
EG23023A (en) 2004-01-31
BR0108245A (pt) 2002-11-05
GB2359104A (en) 2001-08-15
PE20011017A1 (es) 2001-09-21
AR027408A1 (es) 2003-03-26
NO20023772L (no) 2002-10-10

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