CA2339101C - Wellbore fluids containing particulates having acid degradable acetal crosslinks - Google Patents

Abstract

The present invention relates to a wellbore fluid comprising a particulate material composed of the reaction product of: A) one or more water soluble organic compound possessing a molecular weight of less than 30,000 and possessing at least two hydroxyl groups, and B) any other organic compound(s) capable of forming acetal or hemiacetal cross-links with the hydroxyl groups of compound A. The invention relates also to the specific particulate material itself and to applications of the wellbore fluid of the invention for well processes such as drilling, under-reaming, completing, working over, sealing loss zones, sealing fractures, sealing cavities or other very high permeability conduits in a rock formation, or hydraulic fracturing to stimulate a hydrocarbon-producing zone.

Description

WELLBORE FLUIDS CONTAINING PARTICULATES
HAVING ACID DEGRADABLE ACETAL CROSSLINKS

This invention relates to weflbore fluids suitable for use in oiI and gas exploration and production industries and embraces fluids used for drffiing, under-reaming, completion, cementing, fracturing, stimulation, workover and packing of wellbores and also includes spacer fluids whose function is to separate two fluids during pumping operations and spotting fluids whose function is to treat certain intervals of the wellbore.

In the process of rotary drgling a well, a drilling IIuid or nxid is being circulated down the rotatmg dritl pipe, through the bit, and aup the annular space between the pipe acid the fomation or steel casing, to the surface. The dnlting fluid performs diffCrent functions such as removal of drilled cuttings from the bottom of the hole to the surface, suspension of cuttings and weighting material io 'when circulation is mtempted, control of subsurfikoe pressures, nmintaiaing the integrity of the wellbore until the wefl section is cased and cemennted, isolate the fluids from the fornnation by providing sufficient filtration control to prevent excessive loss of fluids to the formation, cool and lubricate the drill string and bit, maxnnise penetration rate etc.

The required functions can be achieved by a wide range of fluids composed of various combin-ation of solids, liquids and gases and classified according to the constitution of the continuous phase niainly in two groupings : aqueous (water-based) d1riII1 ing fluids, and non-aqueous (mineral oil or synthetic-base) drilling fluids, conwmnly 'oil-base fluids' Other types of fluid used 'm well operations include conipWion fluids, a term which corrmmnly refers to fluids pumped after drilling ffinishe.s but prior to starting production, and workover fluids, zo used in remedial opGrations usuaIIy on a well that is already producing.

Brief DescjRtign of the Drawings During the operations for drgmg and completimg hydrocarbon-bearing fornmtions (reservofirs), an overbalance pressure is often applied which oauses fluid loss from the wellbore into the reservoir rock- This filtration process cmses solid particles to block pores in the formation with the build-up of a low permeability internal filtemake cornprised of the solid phases present in the fluid as shown 21 figure 1. The depth of invasion may be from a few millimfts to (occasionally) many centimeters.
T'a 's the Primary cause of damage (loss of productivity) m open hole wells, a phenomenon which is increased by a large overbalaim pressure. Furt}tmmre the formation of a thick filter cake may lead to an increased risk of getting drill pipes or measuring tools stuck in the-wellbore and to failt in cementing the wellbore casings.

Mud solid invasion is also iniportant when the well comprises large natural fractures as shown figure 2. The fractures invaded by the mud are no longer available to drain the oil into the wellbore.
In workover operations, perforations may be also invaded in the same way.

It is therefore highly desirable to provide means to at least minimise formation damage.

High fluid loss, especially spurt loss, tends to increase mud invasion.
Accordingly, additives of a polymeric type such as bioploymers (Xanthan, Scleroglucan), starches and celluloses (hydroxyethyl cellulose[HEC], polyanionic ceIlulose [PAC]) - are added to provide viscosity and fluid loss control.

Usually weIlbore fluids also contain inorganic solids such as clays, barite and calcium carbonate.
When considering mmmnising mud invasion, an important aspect in selecting such itxrganic solids is their particle size distribution for the particks to seal the ei.itrance to pores or ftctvres in the reservoir rock. The "6ridgmg" solids are combined with water soluble or coIloidal polymers to enhance the seaL

Sized particles linnit the depth of invasion as shown figure 3 and 4 where the pore or fracture entrance is sealed with bridging solids. The solids used inclade for instanoe ground silica (especially comrnon in fracturing operdtions), mica, calcium carbonate, ground salts and oil soluble resins.

Another often interrelated approach is to use soluble solids to allow subsequent clean-up with wash fluids. Accordingly sirr,ed calcium carbonate (that can be dissolved by acid and thenefore be mmoved from the pores) is a typical coniponent of dril!-in fluids. The pol.ynm used in conjunction with the calcium carbonate are often selected on the basis that they can also be broken down by acid or enzyme treatments to prevent them impairing the permeability of the fomation.

However, these remedial treatmnts involving the use of strong acid (for instance 15% HC1) have a high cost and can be indaed hazardous and ineffective for the followmg masons.
Poor dissolution of the filter cake can be caused by zones of higher penneability channelling acid away and into the fornation. This can lead to further forimation darttage. Strong acids involve health and safety issues and cause corrosion of sand screens and downhole equipment. Treating a weilbore interval also raises placement issues. Moreover, laboratory tests have shown that the acids can be damaging to the reservoir rock matrix.

_.cause of these limitations therz are many systems and products oti the market to try and improve the perfonnance of filter cake clean up treatments However, these to have associated problems. =
For example, the use of alkalm oxidising agents can kad to problems of iron oxide scale in metal tubulars. Bnzymes take a long time to react and are limited in application by temperature, pH, and s saludty. Tntemal breakers, such as magnesium peroxide, can be added to the reservoir drill-in fluid = so it fonris part of the filter cake. This is then activated by acid to produce hydrogen peroxide to facilitate the breakdown the polymers in the cake. Unforlunately, this can actuaIly happen in the reservoir drill-in fluid whilst drilling which can have a negative effiect on fluid properties.

The present invention auns at providing new wellbore fluids which can form an easy-to-remove t o filter cake.

The invention provides a fluid system that, when used for the purposes of drging, completing, cementir-g, stimulating, packing or working over a wellbore, wi71 facflitate filter cake renzoval.
These can be aqueous or non-aqueous based fluids (such as hydrocacbon based flnids). The result will be reduced or often negligible mpwmmt of permeability of the producing formation by the 15 relevant reservoir servicing fluid compared with well servicing fluids containnW conventional bridging materials.

In accordance with the present invention, acetat crosslinlaed polymsrs are used as the bridging agent in the relevant fluid. In essence the bridging material is made of a particulate material which may swell but is substantially insoluble in water under non-acidic condrtions (at pH >7.5) and which is zo degaded at acidic pH (below 6.5) to substantudly solids-fim or soluble decomposition products.
The partick.s are coniposed of the reaction product of A) one or more water soluble organic compound having posses.sing a nolecular weight of less than 30,000 and possessing at Ieast two hydroxyl groups and B) any other organic conpound(s) capable of forniing acetal or hezmacetal cross-links with the hydroxyl groups of compound A.

25 Exampks of compounds A with free hydroxyl groups capabbe of entehng iato the crosslink reaction of the invention include nionosaccharides, oligosaccharides, polysaccharides of rmlecalar weight less than 30,000, glymrol, polyglyc=ls, erythrrtol, pentaeryRhritol, mannitol, rorbirtol, glycols, polyalkykne glycols, and low molecular weight water soluble vinyl polymers possessing hydroxyl groups.

Suitable acetal crosslink agents B include aliphatic monoaldehydes and dialdehydes having from. .o carbon atoms and esters of propioiic acid wherein the alcohol forming the ester has from 1 to 8-carbons. A preferred conipound is 1,5 pentanedial (glutaric dialdehyde) CS118O2.

Usually, the anlaunt of cross-linking agent varies from 0.5 to 15% w/w (and the amount of s compound A accordingly varies from 99.5 to 85% w/w).

An example of a useful material has been prepared from 95% yellow dextrin (a gum produced from the acid hydrolisis and depolymerisation of starch feedstock) and 5% by weight pentanedial.

Acetal crosslinked starches are known from U.S. Patents 4,048,435 and 4,098,997 that describe methods of prepamg reversibly crosslinked granular starches for use in the paper, adhesives and 10 textile industries but with no mention as to their potential use in the oil industry. It is staxed that these starches contain acetal crosslinkages, which are stable under neutral or alkaline conditions but which readily hydrolyse under acidic conditions, and they are designed to dissolve and form a colloidal suspension in water. By contrast, the present invention contemplates the cross-liaking of much lower molecular weight polyols than the above mentioned starches to produce a partwulate suspension where the particles do not dissolve or disperse at ai(caline pH.

The solid may be ground or prepared to any desired particle size.

The particles are stable under allcaline conditions and insoluble (but usuaily swelI) in aqueous wellbore fluids of pH 7.5 and above. Thus they provide very effective sealing of the formation by virtue of the swollen particles' ability to deform to `Yit" the pore openings or fractures.

Most advantageously however, the cross links rapidiy hydrolyse under acidic:
catalysed conditions, under even weakly acidic conditions at pH 6.5 and below. The degradation products are essentially solids free water solubk noieties of low molecular weight and low viscosity in solution. Hence any flow restriction (of hydmcarbons) caused by the particles may be efficiently removed. A low pH
solution such as a weak easily-handled acid of little corrosion potential ma.y be pumped in place to catalytically degrade the particles. Alternatively, produced fluids, be they oil and water or gas and water, usuaIly exhibit an aqueous pH of less than pH 6.5 due to the carbon dioxide commonly present. Hence the removal of the teniporary seal may be triggered simply by allowing the well to flow. As the seal degrades the well flow increases autocatalytically.

hydrolysis does not consume the acid Hence much enhanced clean up and optimised well productivity is anticipated compared to that exhibited when using current materials such as ground -calcium carbonate.

The following features and benefits have been identified with the use of acetal crosslinked, polymeric, bridging solids:

= Fdter cakes made from these novel nuterials ahnost totally degrade in the presence of weak acid gn-ing almost 4x the return flow rate compared to a conresponding calcium carbonate based fluid under the same conditions. This also gives the benefits of better health and security from handling weak acids and less corrosion of downhole screens and equipment.

i o = A feature of the invention is that the degradation of the acetal bridging material is acid catalysed, as opposed to the conventional stoichiometric reaction. This means the acid is not consumed or neutzalised in the reaction. The benefit of this is an enhanced acid treatment as the acid is avabbk to go on degrading mwre filter cake.

= Due to the high mobility of the hydrogen ion, (which can therefore penetrate the water-swollen particles) the acid does not have to be forced into the filter cake to break it down. Which means that less acid induced damage results from strong acid being forced into the fonmation causing fines to migrate, bridge and restrict production.

= Acetal crosslittked bridging mat.erials can degrade under sualated well flowing conditions in the laboratory, where the weak acid is provided by produced COZ forming carbonic acid in the zYqueous phase. This could negate the need for a costly wash fluid treatnrnt.

= Acetal bridging materials have a low density. A low density wM enable a wider range of appfications to be covered, density constraints often limit the amount of btidgimg solid which can be used. Calcium carbonate has a density of 2.7 S.G. and cannot always be added at the desired concentrations for bridging in low density fluids. Anottler benefit wdl be improved removal of undesirable, non acidisable, contaminatmg solids, from the flnid.
Contanvnating solids from the fonmation have roughly the same deasity as calcium carbonate which makes separation d'tfl'icnlt in a conventional fluid. However, these solids are approximately 2.7 times denser than the acetal bndgmg solid. This nmns that highly efficient separation techniques, such as centrifugation, can be enipbyed to remove non acidisabie solids from the fluid without n:moving the aceal lnidging solids. This therzfore makcs the fluid less formation damaging.

Preparation of an acetal bridging solid.

95 weight parts of dry yeIlow dextrin was dissolved in water and 5 weight parts pentanedial added.
The saniple was mixed and heated to 130 C. The water was then removed under partial vacuum over a 16 hour period. The solid from this was then ground to a fine particle size (substantially all less than 150 microns) and tested as follows.

The wellbore fluids in the following examples have been tested using a high pressure/high temperature fluid loss cell as schematically represented figure 5. Such an apparatus typically comprises a measuring cell I closed by an upper cover provided with a central passage 2 and a bottom provided with a drain 3. The bottom is covered with a base ma& of a porous material, in this instaix;e a 5 micron aloxite disc. Gas can be injected to provide the dfferentiai pre.ssure between the mud and the formation fluids. The product doses are expressed in pounds per barrel (ppb).

is Example 1 A fluid system of this invention (Acetal fluid) was compared to one of conventional formulation, CaCO3 based fluid (conVa.son fluid) containimg 49ppb cakium carbonate bridging solids, 6ppb DUALFLO' filtration control additive, lppb IDVIS'a' viscosifier and suspending agent, 25ppb CaC12, 2ppb PTS200 alkaline buffer.

The Acetal fluid contains - 40ppb ACETAL bridging solids, 6ppb DUALFLO, lppb IDVIS, 43ppb KCI, 2ppb P'TS200.

The testmg of the fluids was according to the following protocol, schenWically illastrated figure 5 where the arrows indicate the direction of the fluid flow in the core plugs (the upwards arrow corresponds to fluid loss from the subterranean rock to the weIIbore whfle the downwards arrow characterises fluid loss from the weIlbore into the subtenmnean rock).

6 .

fl:

= Step 1: `apply' mud danmage, using the tested wellbore fluid, to a 5 micron aloxite disc under typical well conditions (temperature 80 C, pressure of 500 psi). Fluid loss is measured after -15.5 hours (downwards arrow). A filter cake is formed on the aloxite disc.

= Step 2: cell emptied hot and refilled with 10% NaCI brine and 12/20 sand. A
45 micron aperture screen was then placed on the sand. The sand is used for modeIling a gravel pack which may be placed in a well to control sand production.

= Step 3: simulates the flow from the reservoir oil into the wellbore through the filter cake (upwards arrow) , using kerosene flow back and a typical formation pressure of 4 psi with carbon dioxide as the pressuring gas at 80 C.

= Step 4 : Flow 500g of COz containing kerosene, shut the cell and leave for 64 hours at 80 C
and then test the flow rate in the production direction Sample 15.5 hr. Fluid loss Flow rate after shut in (ml) (g/min) CaCO3 bridging solids 17 22..2 Acetal bridging solids 20 33.6 The example illustrates the effect that an ACETAL fluid filter cake is degraded in the presence kerosene containing dissolved carbon dioxide. The return flow rate for the ACETAL fluid was 1.5 x higher than for the CaCO3 fluid. This test suggests that naturally occurring fluids from a production zone will degrade the filter cake even in the absence of applied acid. It can also be seen that using all acetal bridging solids gives a slightly higher fluid. loss. It was found that the use of a snull amount of calcium carbonate in conjunction with the acetal solids reduced the filtrate loss, allowing a lower concentration of DUALFLO fluid loss additive to be utilised in the following exannples.

Example 2 The CaCO3 based fluid contains - 40ppb calcium carbonate, 6ppb DUALFLO, lppb IDVIS, 43ppb KC1, 1 ppb PTS 100.

The ACETAI. based fluid contains - 7ppb calcium carbor,iate, 30ppb ACETAL
solids, 3ppb DUAI.FLO, 1 ppb IDVIS, 43ppb KCl, 3ppb PTS 100.

The following test protocol is used = Step 1: `apply' mud damage, using the tested wellbore fluid, through a 5 micron aloxite disc at a temperature of 80 C and a pressure of 500 psi. The fluid loss is measured after 15.5 hours.

lo = Step 2: cell emptied hot and refillec3 with 100 ml 5% citric acid as a moderated acidic wash fluid.
= Step 3:. Reseal cell, do not pressurise, leave 72 hours at 80 C

= Step 4: Open cell and fill with 12-20 sand and fit 45 micron aperture screen = Step 5: Carry out kerosene return flows at 4psi, at a temperature of 80 C.

Sample 16.5 hr. Fluid loss Flow rate (gJmin) pH of produced (mt) fluids CaCO3 fluid 23 21.2 5.9 ACETAL fluid 17 80.9 2.0 The example signifies that under mild acid conditions the rethun flow rate for the ACETAL fluid was nearly 4x higher than for the CaCO3 fluid, indicating that the ACETAL
fluid filter cake has degraded to a much greater extent. This was confmned on opening the cell which showed the presence of a large filter cake for the CaCO3 fluid and little to iio filter cake for the ACETAL fluid.
The lower pH of the produced fluids from the cell containing the ACETAL fiiter cake indicates that the acid is not being used up to the saine extent as with CaCO3 filter cake.
The example also deinonstrates that the filter cake is degraded without pressurisation of the cell. Conventionally, these tests are typically carried out under pressure to force acid into the cake.

Example 3 The CaCO3 based fluid contains - 40ppb calcium carbonate, 6ppb DUALFLO, 1 ppb IDVIS, 43ppb KCI, 2ppb PTS200, 15ppb OCMA clay.

The ACETAL based fluid contains - 7ppb calcium carbonate, 30ppb ACETAL solids, 3ppb DUALFLO, lppb IDVIS, 43ppb KCI, 3ppb PTS 100 15ppb OCMA clay.

The test protocol of example 2 was used except that step 1 lasted only 15.5 hours and step 3 20hours.

Sample 15.5 hr. Fluid loss Fllaw rate (MI) (g/min) CaCO3 flaid 32 9.8 ACETAL fluid 18.8 21.4 The example demonstrates that an ACETAL fluid filter cake containing non acidisable OCMA clay is degraded by weak acid in a short time. The return flow rate for the ACETAL
fluid was 2.2 x higher than for the CaCO3 fluid, indicating that the ACETAI, fluid filter cake has degraded to a much greater extent.

Example 4 2o The CaCO3 based fluid contains - 40ppb calcium carbonate, 6ppb DUALFLO, lppb IDVIS, 43ppb KCI, 2ppb PTS200.

The ACETAL based fluid contains - lOppb calcium carbonate, 30ppb ACETAL
solids, 3ppb DUALFLO, lppb IDVIS, 43ppb KCI, 2ppb PTS200.

The foIlowing test protocol was used :

= Step I:`apply' mud damage, using the tested weIlbore fluid, through a 5 micron aloxite disc at a temperature of 80 C and a pressure of 500 psi. The fluid loss is measured after 15.5 hours.

= Step 2: cell eniptied hot and refilled with 0.1m (0.37%w/v) HCl and 12/20 sand and a 45 micron aperture screen fitted.

= Step 3: The cell was resealed and left for 4hours @ 80 C

io = Step 4: then kerosene flow backs carried out at 4psi and 80 C.

Sample 15.5 hr. Fluid loss (mi) Flow rate (g/min) CaCO3 fluid 29 20.7 ACETAL fluid 16 32.0 The example demonstrates that exposure of ACETAL fluid filter cake to even a highly diluted acid causes it to degrade in only a short time. The return flow rate for the ACETAL
fluid was 1.5 x higher than for the CaCO3 fluid.

Claims (8)

WHAT IS CLAIMED IS:

1. A wellbore fluid comprising a substantially water non-soluble particulate material that is degradable under acidic conditions and composed of the reaction product of A) one or more water soluble organic compound having a molecular weight of less than 30,000 and possessing at least two hydroxyl groups and B) any other organic compound(s) forming acetal or hemiacetal cross-links with the hydroxyl groups of compound A.

2. The wellbore fluid of claim 1 wherein hydroxyl compound (A) is selected from the class consisting of monosaccharides, oligosaccharides, polysaccharides of molecular weight less than 30,000, glycerol, polyglycerols, erythritol, pentaerythirtol, mannitol, sorbitol, glycols, polyalkylene glycols, and water soluble vinyl polymers possessing hydroxyl groups.

3. The wellbore fluid according to claim 1 or 2, wherein compound (B) is selected from the class consisting of aliphatic aldehydes and dialdehydes having from 2 to 10 carbon atoms, and esters of propiolic acid wherein the alcohol forming the ester has from 1 to 8 carbon atoms.

4. The wellbore fluid of claim according to claim 1, wherein 0.5-15%, dry weight of compound (B) and 99.5-85% of said compound (A) is reacted.

5. The wellbore fluid according to claim 1 wherein the substantially water non-soluble particulate material is the reaction product of dextrin and petanedial.

6. A process of drilling, under-reaming, completing, working over, sealing loss zones, sealing fractures, sealing cavities or other very high permeability conduits in a rock formation, or hydraulic fracturing to stimulate a hydrocarbon-producing zone comprising using a wellbore fluid comprising a substantially water non-soluble particulate material that is degradable under acidic conditions and composed of the reaction product of A) at least one water soluble organic compound having a molecular weight of less than 30,000 and possessing at least two hydroxyl groups and B) any other organic compound(s) capable of forming acetal or hemiacetal cross-links with the hydroxyl groups of compound A.

7. The process of claim 6 further comprising:

pumping a low pH fluid containing any acid or buffered solution of less than pH 6.0 into a producing zone segment of the wellbore to catalyse the decomposition of the particulate material.

8. The process of claim 6 or 7, further comprising allowing a well in which the wellbore fluid is used to flow, causing a drop in pH, which catalyses the decomposition of the substantially water non-soluble particulate material, permitting increased flow of produced fluids.