CN113574135A

CN113574135A - Composition for making drilling fluid non-invasive

Info

Publication number: CN113574135A
Application number: CN202080020481.6A
Authority: CN
Inventors: 简·克里斯蒂安·瓦斯胡斯; 卡尔·罗尼·克隆特维德; 斯瓦潘·库马尔·曼达尔
Original assignee: European Mulder Co ltd
Current assignee: European Mulder Co ltd
Priority date: 2019-03-13
Filing date: 2020-03-13
Publication date: 2021-10-29
Also published as: GB2595161A; CA3132033A1; GB2595161B; GB202111649D0; NO20191461A1; NO345560B1

Abstract

The present invention relates to a composition for rendering a drilling fluid non-invasive, the composition comprising: a first component comprising particles having a scratch hardness of greater than 2 Mohs; and a second component comprising particles selected from crushed seeds of sour beans, crushed bark of Litsea glutinosa or crushed corona petiolata. The invention also relates to a non-invasive drilling fluid comprising the composition, and a method for drilling a wellbore.

Description

Composition for making drilling fluid non-invasive

Technical Field

The present invention relates to a composition for making a drilling fluid non-invasive, a non-invasive drilling fluid comprising the composition and a method for drilling a well.

Background

Drilling fluids (or "muds") used in the drilling of subterranean oil and gas wells, geothermal wells, mining and other drilling applications are well known. The drilling fluid carries drill cuttings and other particles below the drill bit, transports them through the annulus, and allows them to separate at the surface while cooling and cleaning the rotary drill bit. The drilling fluid also aims to reduce friction between the drill string and the side of the borehole, while maintaining stability of the uncased section of the borehole. The drilling fluid is formulated to prevent the undesirable influx of formation fluids from the permeable rock being penetrated. Drilling fluids may also be used to collect and interpret information available from drill cuttings, cores, and electrical logging. It should be understood that the term "drilling fluid" as used herein also includes "drilling fluid" and "completion fluid".

In the oil and gas industry, deep well drilling faces a range of challenges, such as wellbore instability, stuck drilling, lost circulation, high torque and drag, collapse and breakout, drill bit balling, and formation damage. Specially designed drilling fluids are used to overcome most of these problems. The primary functions of these drilling fluids are to clean the wellbore (by removing cuttings), seal permeable formations (forming a filter cake at the surface of the borehole), cool and lubricate the Bottom Hole Assembly (BHA) and drill bit, increase the rate of penetration, maintain wellbore stability, and minimize damage to the reservoir.

One of the causes of wellbore instability is the presence of microcracks at the borehole surface. If the hydrostatic pressure of the drilling fluid is higher than the formation pressure, the drilling fluid may penetrate the microfractures and increase the pressure therein, also known as pore pressure transmission. Due to this pressure transfer, the pressure differential between the hydrostatic pressure of the fluid and the formation pressure (which creates a pressure differential that supports the sidewall by pushing towards the formation) will be reduced, whereby the hydrostatic pressure differential will provide less support to the sidewall. This may lead to hole instability.

Another common problem encountered during drilling operations includes fluid loss and/or leakage loss. In this disclosure, the term "fluid loss" will be used to refer to the more severe drilling fluid loss that often occurs where porosity and microcracking are significant. In the present disclosure, the term "leakage loss" will be used to refer to a less significant loss of drilling fluid in areas where porosity and fracture size are small. Fluid loss and seepage loss occur when the liquid portion of the drilling fluid penetrates the surrounding formation, leaving the solid particle portion of the drilling fluid in the wellbore. Fluid loss and seepage loss may occur in any type of formation when the size of the particles in the well fluid is less than the size of the formation pore openings. This loss is caused by the formation actually filtering the solids due to the pressure differential from the fluid column to the formation.

To control the loss of the drilling fluid to the formation at low to medium differential pressures (typically tested up to 500psi) and low to medium permeability, different methods are used for oil-based and water-based drilling fluids. This is commonly referred to as filtration loss control and can be tested by standard API units and High Temperature High Pressure (HTHP) filtration units at 100psi or 500psi pressure differential. For oil based drilling fluids, additives such as gilsonite, bitumen, amine treated lignite or organophilic clays are commonly used to improve filtrate loss control. For water-based drilling fluids, a range of polymers, such as polyanionic cellulose (PAC) and starch, are additives that improve fluid loss control. The polymers used are generally water-soluble.

In contrast, non-invasive drilling fluids (NIFs) typically contain additives that are primarily dispersed rather than dissolved in the fluid. NIF additives are capable of sealing formations with higher permeability as well as fracture formations and are at higher pressures where conventional fluid loss control is not effective in sealing the wellbore. The non-invasive fluid is a drilling fluid that rapidly seals pores or microfractures after being drilled, thereby reducing the chance of wellbore instability. By providing a physical barrier, the same measures can also be used to prevent formation damage in the production zone, thereby isolating the production zone from the fluid column and reducing damage.

In the context of the present application, a non-invasive fluid is considered to be a fluid that can be tested by either:

API HTHP test (30 minutes, 500psi, 90 ℃), with less than 40ml of fluid filtrate when using ceramic disks with an average pore throat of 50 μm and a permeability of 15Darcy (e.g., Ofite # 170-53);

an API HTHP test (30 minutes, 500psi, 90 ℃) test, with less than 20ml of fluid filtrate when using a ceramic disc with an average pore throat of 20 μm and a permeability of 3Darcy (e.g., Ofite # 170-53-3); or

100psi pressure differential sand bed test, carried out at 25 ℃ for more than 10 minutes, with sand sizes between 30 mesh (about 595 μm) and 40 mesh (about 400 μm), with an intrusion of less than 45 mm.

The prior art has many disclosures regarding cementing wells that penetrate subterranean formations. In such operations, drilling fluids (commonly referred to as "muds") are typically present in oil wells and other similar wells when casing is cemented into a borehole with an aqueous cement slurry. Since mud and cement are not always compatible with each other, it may be desirable to separate or prevent contact between them through the use of a non-invasive drilling fluid system. Without such a non-invasive drilling fluid, the incompatibility of the aqueous slurry and the oil-based mud can be so severe that the mixture of the two forms an unpumpable mass. Such a non-pumpable mass may prevent displacement of at least a portion of the drilling fluid. Non-invasive drilling fluids are also used to wet the surface of the wellbore to promote the adhesion of the cement sheath to the wellbore and casing.

The prior art fluids are designed as turbulent spacer fluids at low shear rates, allowing them to displace viscous drilling mud from the wellbore. Some turbulent fluids have certain disadvantages, such as instability under operating conditions, especially at the higher temperatures possible at the bottom of the wellbore. In the case of separate drilling fluids, such mixing and remixing can result in reduced separation performance, contamination of the leading edge of the cement or cement slurry with the drilling mud, limited ability to move the drilling mud in the wellbore, and a reduction in the sweep efficiency of the water-based mud. These disadvantages generally have a detrimental effect on the quality of the cementing operation in the borehole. For example, the performance of the set cement slurry may be compromised in its ability to bond with both the exposed rock surface in the drilled wellbore and the tubulars placed in the wellbore due to insufficient removal of the drilling fluid.

The invasion of mud filtrate may be reduced by forming a thin barrier of low permeability on the borehole wall or plugging the pores or microfractures of the borehole wall. Traditionally, this has been successfully accomplished by using pore sealants such as latex, asphalt, alumina polyhydroxide or sodium/potassium silicate precipitation mechanisms, or by forming a soft, compressible cellulose particle barrier on the surface of the borehole.

While some solids invasion and formation damage are inherent to all drilling fluids, damage caused by solids invasion and the depth of such damage can be minimized by properly sizing the bridging particles in the drilling fluid. Drilling fluids that limit the invasion depth to within a few millimeters or do not allow any mud to further invade the formation are known as non-invasive fluids (NIFs) or ultra-low-invasive fluids (ULIFs).

NIFs typically comprise a mixture of particles that are carefully sized to seal fractures of a given size or range of sizes. These components are typically fixed size solid particles or fixed size polymeric materials, such as cellulose based fibers, which form an impermeable membrane. It has been observed in the past that during conventional drilling, when NIF component addition is programmed for invasion control, it is added to the old drilling fluid. Such NIF compositions are known to use ultra-fine drilling solid particles and activated colloidal clay (also known as MBT) generated during the drilling process to help form a final tight seal on the membrane. Ultra-fine drilling solids and activated clays have been said to have been used to form thin films that limit fine migration and reservoir damage. During this process, some fine migration of ultrafine solids may occur in the reservoir pores, which will partially plug the pores and undesirably reduce production.

US20100243236 patent application discloses nanoparticle dense newtonian fluids for use as cementing and completion spacers in oil and gas wells.

Many different types of organic materials have been used to address leakage losses.

US6,399,545 patent document discloses the problem of leakage loss or fluid loss, including describing the use of marc in drilling fluid additives.

The US5,071,575 patent document describes the use of ground oat hulls in a limited particle size range and the addition of one or more agricultural by-products such as ground citrus pulp to reduce leakage losses.

The US5,229,018 patent document teaches the use of peanut shells as an additive.

The US5,076,944 patent document discloses the use of cotton drill cuttings (cotton buns) in combination with one or more of ground oat hulls, ground corn cobs, hydrophobic organophilic wettable cotton, ground citrus pulp, ground rice hulls, ground nut shells and mixtures thereof as a leakage loss additive.

US5,801,127 patent document discloses the use of ground olive pomace as an additive to prevent fluid loss in water-based and oil-based drilling fluids.

While organic additives are generally less expensive than inorganic additives and are generally environmentally safe, not all organic additives provide a particle size distribution that is broad enough to prevent leakage loss or fluid loss under a wide range of drilling conditions. Some additives may be used as lost circulation additives, but are not effective for fluid or leakage losses. In addition, some additives affect the permeability of the surrounding formation. Also, some organics tend to form sticky agglomerates (mud balls) that significantly reduce penetration of the drill bit. These viscous deposits often form a mud ring as the fluid attempts to bring them up the borehole wall.

Because each drilling operation is different, there remains a need for a drilling fluid additive that addresses fluid loss and/or seepage loss under various drilling conditions, that will be compatible with water-based or oil-based drilling fluids, and that will not adversely affect the flow characteristics of the surrounding subterranean formation. In particular, the challenges of fluid loss, well control, and formation damage are important when drilling into a hydrocarbon reservoir, where the pressure in the formation fluid is reduced due to the production of the reservoir. During drilling, situations arise where the pressure differential between the drilling fluid and the formation fluid in the well reaches thousands of psi or hundreds of bars. In many cases, prior art NIFs do not have the strength to seal the pore throats and/or cracks under such high pressure conditions, resulting in pressure transmission and fluid loss. There is also a need for additives that do not adversely affect the lubricating properties of the well fluid. Accordingly, there remains a need in the art for improved non-invasive drilling fluids that overcome the above-mentioned disadvantages. There is also a need for a non-invasive drilling fluid that can effectively remove particles such as drilling mud as well as liquid contaminant particles. There is also a need to be able to remove the barrier filter cake prior to production to clean the formation and achieve optimal production from the well.

Disclosure of Invention

It is an object of the present invention to remedy or reduce at least one of the disadvantages of the prior art or at least to provide a useful alternative to the prior art. This object is achieved by the features specified in the description below and in the appended claims. The invention is defined by the independent patent claims, while the dependent claims define preferred embodiments of the invention.

In a first aspect, the present invention relates to a composition for rendering a drilling fluid non-invasive, the composition comprising: a first component comprising particles having a scratch hardness of greater than 2 Mohs; and a second component comprising particles selected from the group consisting of crushed seeds of tamarind (Tamarindus indica), crushed bark of Litsea glutinosa (Litsea glutinosa) or crushed mini-corona fumigant (oxicum tenuiflorum). Sour beans are also referred to herein as tamarind seeds (tamarind seed), litsea glutinosa bark is also referred to herein as guava (jiggat), mini-guanfu is also referred to as holy basil (Ocimum sanctum, holy basil, tulasi and tulsi), and is referred to herein as tulsi. The particles may be prepared, for example, by grinding or crushing.

A scratch hardness of 2 on the Mohs scale may correspond to about 61kg/mm on the Vickers scale²The hardness of (2). Mohs scratch hardness is a standard practical method known to those skilled in the art. In short, to determine the scratch hardness of an unknown material, it is differentiated from others having known scratch hardnessThe material is scraped. If the unknown material in question dents, its scratch hardness is lower than other materials. Otherwise, if the other material is dented, the scratch hardness of the unknown material is higher than that of the other material. This can be repeated with several other materials to determine the scratch hardness with the required accuracy. For example, the scratch hardness of walnut shells or almond shells is typically 3-4Mohs, while calcium carbonate, having a hardness of 3Mohs (calcite), is considered to be a soft mineral. The hardness reference of 2Mohs is gypsum (CaSO)₄·2H₂O). Thus, when the particles of the first component are scraped over the gypsum, the gypsum will sag rather than the particles of the first component. The hardness of the first component may typically be less than 8.5Mohs, as higher hardness values may result in poor contact of the particles of the first component with other particles.

The composition may generally be in the form of an additive for addition to a fluid, such as a drilling fluid. If the composition is mixed into a fluid (e.g., a liquid) and pressure is applied to the fluid in an attempt to compress it against the porous or permeable material, the components of the composition form a thin impermeable film or membrane that covers the porous openings of the material. This is basically the case in wells during drilling, where the formation is porous or permeable and drilling fluid is pumped into the well for the reasons mentioned above. By using the composition in a drilling fluid during drilling, the drilling fluid will be a non-invasive drilling fluid. Pressure applied to the fluid will result in the formation of an impermeable membrane on the surface of the porous or permeable portion of the well so that substantially no fluid is lost to the formation after membrane formation. Thus, instead of plugging the microfractures of the formation by particles entering the microfractures as taught by the prior art, the membrane created by the present invention will cover the open portions of the microfractures and be held in place by the pressure applied to the drilling fluid. Thus, the composition will be particularly suitable for use in drilling fluids for drilling production zones where it is important that the pores or microfractures are not permanently plugged. In this way, after drilling of the well is completed and the pressure on the drilling fluid is removed, the pressure in the production zone formation will be greater than the pressure in the well, so that the membrane can be automatically pushed out and removed. Thus, no additional processing steps are generally required to remove the film, such as the use of an acid. However, additional processing steps may still be used if desired. For example, most membranes can be dissolved using NaOCl, optionally followed by HCl if the desired solubility is not achieved. The solubility of the films made from this composition in 5 wt% NaOCl and then 16 wt% HCl is typically over 90 wt%. This can be used to dissolve the membrane in the well. Thus, use of the composition in drilling a drilling fluid may result in reduced formation damage and increased return permeability, thereby increasing well production. During production zone drilling, the operator may dump all drilling fluid that may contain dirty mud and then replace it with new non-destructive and non-invasive drilling fluid because of the poor return permeability of most conventional mud systems.

It has been observed that the composition based on the present invention provides a membrane capable of withstanding higher pressures than the prior art NIFs. The mechanism of film formation is believed to be the interlocking of the first component and the second component, wherein the particles of the first component act as a bridging agent that provides strength to the film, and the particles of the second component act to link together with the particles of the first component. It has been observed that the particles of the second component provide greater binding than known in the prior art. This effect is believed to be due to the specific type and distribution of the biomolecules in the particles of the second component. The class and distribution of macromolecules within the group may differ, and thus the mechanism of action may differ slightly. However, when mixed into water and subjected to increased pressure, all particles of the second component have been shown to provide films with good properties. It is believed that such increased pressure, for example downhole, deforms the particles of the second component such that the contact area and friction between the particles of the first and second components may increase. As the pressure increases, the membrane becomes even less permeable to fluids and stronger.

The binding action of the particles of the second component will make the particles more likely to stick together and form a strong, flexible film. It has been observed that the adhesive properties increase with increasing temperature, especially when the temperature reaches about 55 ℃. This increase in adhesion may be referred to as activation of the components, which may be achieved, for example, by raising the temperature in the fluid in which they are suspended, for example, above 50 ℃. In addition to temperature, the time of the particles in the fluid is also an important factor in the activation of the components. This is because the binding of the particles of the second component is usually obtained after hydration of the particles. Longer times in the drilling fluid increase the adhesion properties until maximum adhesion is reached. The adhesion may be in the form of mucoadhesive, gum, gelling or film-forming properties. In addition, increased pressure is required to form the membrane. Thus, the specific composition of the drilling fluid, temperature, hydration time, and pressure may be varied to obtain the optimal parameters for a particular well. Further, the first, second, and any other components may be varied based on specific properties such as compressibility, flexibility, solubility, micro-sealing efficiency, and adhesion to optimize the drilling fluid for a particular situation. The binding effect may be caused by phytochemicals in the second component, where more than 20% of the component may be protein, acid, oil or non-fibrous carbohydrates, which are either insoluble or poorly soluble in water. Adhesion is generally observed in the hydrated state of the second component and not in the dry state.

The composition may be applied to a drilling fluid at a concentration of 4 to 10 pounds per barrel (ppb) for prophylactic treatment of loss of drilling fluid to a permeable or fractured formation to convert the drilling fluid to a non-invasive fluid. 1ppb is 2.85kg/m³Therefore, 4 to 10ppb corresponds to 11.4 to 28.5kg/m³. Alternatively, the composition may be used up to 30ppb, corresponding to 85.5kg/m³Is used as a pill or as a scavenger of seal loss after occurrence. By keeping the concentration in the drilling fluid below 30ppb, the particles of the composition will remain substantially dispersed without the risk of settling and plugging equipment components. Then, after applying a differential pressure, a film was formed on the microcracks. As the particles of the composition form a film in the well during drilling, it may often be necessary to add more composition while drilling to maintain the concentration of the composition and thus the film forming properties of the drilling fluid.

Thus, the compositions based on the present invention may have film forming properties when dispersed in a solution such as a drilling fluid, especially when subjected to increased pressure and temperature. By using this composition, it is possible to convert the drilling fluid into a non-invasive drilling fluid without the presence of additional solids in the drilling fluid, and thus the drilling fluid may also be a solids-free drilling fluid. In this discussion, by definition, a solids-free drilling fluid is a drilling fluid that does not use particles as weighting materials (e.g., barite, hematite, calcium carbonate), or where solids (e.g., fine drill cuttings and clays) that become part of the drilling fluid during drilling operations are not required to prevent drilling fluid leakage. However, the presence of any solids in the drilling fluid does not hinder or reduce the film forming properties of the fluid containing the composition. In some cases, the use of casing strings may be avoided because non-invasive drilling fluids can withstand pressure differentials in excess of 4000 psi. This will significantly reduce the cost of the well. The presence of solids in the drilling fluid, such as weighting materials or fine drill cuttings, may enter the formation and may reduce permeability, thereby reducing the ability of the formation to transport fluids as expected during the operational phase. Formation damage caused by this type of drilling fluid can significantly reduce subsequent production or injectivity, thereby reducing the value of the well. The invention can be used to effectively form a temporary seal on the wellbore wall, thereby reducing drilling fluid induced formation damage and better preserving formation permeability and well value. The temporary sealing film created by the present invention may be removed by application of back pressure, a breaker solution and/or application of an acid. Depending on the application, the sealing membrane may also be permanently fixed in place, if removal is not desired, for example as a foundation for cementing.

The composition may additionally comprise a third component having anisotropic mechanical properties or shape and an elastic modulus at least in the longitudinal direction El of more than 2000MPa and less than 40000 MPa. The anisotropic mechanical properties of the third component will promote elastic deformation, whereby these particles will reinforce the film formed by the particles of the first and second components and aid sealing. Thus, the effect of the third component will be to make the membrane even more flexible to pressure differences, so that the membrane can withstand even higher pressures without rupturing. An example of a third component may be western white pine (Pinus monicola), which typically has a modulus of elasticity in the longitudinal direction of around 8600MPa, or Populus tremula (Populus tremula), which has a modulus of elasticity of around 8000 MPa.

The particles of the second component are both biodegradable and the first and third components may also advantageously be biodegradable or of biological origin, so that the composition does not contaminate the environment. The component may include, for example, a plant part, such as a plant fiber. The plant fiber may be a biopolymer, such as a polysaccharide. For example, the first and third components may comprise cellulose, as the molecular structure of the cellulose fibers may provide some of the beneficial properties described above. Furthermore, cellulose is biodegradable and cellulose containing materials can be easily obtained, for example as waste products of food production. For particularly beneficial mechanical properties, a majority of at least one of the first component and the other component may be cellulose.

The first, second and third components may be capable of being exposed to temperatures up to at least 150 ℃ without losing the ability to create a pressure resistant film, and for certain combinations up to 200 ℃ without losing the ability to create a pressure resistant film. The particles will therefore be particularly suitable for use in drilling fluids, as the temperature in the well can be very high.

Forming the membrane rather than blocking individual microcracks also reduces the problem of the prior art that the size distribution of bridging particles of the non-invasive fluid needs to be complementary to the size distribution of the cracks, as microcracks having a broader size distribution will be covered to form the membrane. Therefore, less knowledge of the microfractures is required during drilling. For example, the particles may follow a bell-shaped or normal size distribution in which the particles, or for example at least 90% of the particles, may pass through a 60 mesh sieve, i.e. 250 μm x 250 μm openings, while the particles, or at least 90% of the particles, may not pass through a 450 mesh sieve, i.e. 32 μm x 32 μm openings. This particle size range would be suitable for forming a film on microcracks having typical sizes, but other particle size ranges may be suitable for microcracks of other sizes. In this application, when referring to dimensions of e.g. up to 250 μm, this means that the particles can typically pass through a sieve with openings of 250 μm x 250 μm. For example, the size distribution of the particles may be selected such that 90% of the particles are up to 180 μm in size (i.e., can pass through a sieve having an 80 mesh screen). This has the advantage that during drilling the particles will subsequently pass through an 80 mesh screen, which is commonly used in solids control systems, and will remain in the active system rather than being screened out. The particles may also have a maximum value of at most 150 μm. The particles may have a suitable size distribution, for example wherein about 75% of the particles are less than 150 μm but greater than 20 μm in size and 5% are less than 20 μm in size. In this way, the smaller particles will form a good seal, while the presence of about 20% of the larger particles will help to form a film over the larger cracks. If the cracks are larger, the size distribution of the larger particles can be selected. If a relatively broad particle size distribution is used in the composition, the film will more readily conform to form a network for sealing fractures or pore throats and connecting particles and formations having different sizes and shapes. Most particle preparation methods, such as milling of the components, naturally result in a broader particle size distribution. The preparation of the composition is therefore simple.

The mixture comprising the first, second and third components may have a combined specific gravity in the range of 0.7 to 1.1. The low specific gravity of this combination may facilitate application in a drilling fluid without increasing the specific gravity of the fluid and thus avoid creating increased hydrostatic pressure in the wellbore. In combination with the function of this drilling fluid as a wellbore strengthening material, the low specific gravity of the components may facilitate large displacement drilling and formation drilling not achievable using prior art techniques.

The advantageous binding effect provided by the particles of the second component may be due to the significant presence of specific extracts such as terpenes, resin acids, fatty acids, amino acid polymers, oils, lignins, tannins, phenols and/or non-starch polysaccharides. For example, acid bean seeds may generally contain high concentrations of materials that may be described as natural polymers, natural gums, acid bean seed polysaccharides (TSPs), non-fibrous carbohydrates, non-starch polysaccharides, uronic acids, and/or hexoses. In combination with water, this may have the effect of swelling, gelling, thickening or acting as a binder. In addition to the hydrogen bonding interactions that are typically present between soluble low molecular weight sugars and starch, the presence of the combination of one or more of the above extracts with cellulose (which will also be contained in the particles of the second component) may induce covalent bonds, such as glycosidic and/or amide/peptide bonds in the protein molecules. The exposure of this effect to high temperatures may increase. Such molecular bonds may be stronger than the hydrogen bonds created between cellulose particles by dehydration of hydrated cellulose. The hydrophobicity due to the presence of organic molecules with lower hydrophilic-lipophilic balance (HLB) values prevents the extract from dissolving in water. Due to their partial solubility in water, these extracts remain coated on the cellulose surface and act to attach cellulose particles. Thus, increasing the bonding between different cellulose particles by the above-mentioned extractives may contribute to the advantageous properties of the film formed from the composition. The presence of organic acids and low molecular weight sugars is known to produce stickiness in foods, whereas cellulose-based polysaccharides do not contribute significantly to stickiness. Adhesion may also occur via xyloglucan chains adhering to the cellulose particles or forming a film on the particles.

By adjusting the composition and concentration of the components in the fluid, viscosifiers other than ordinary bentonite may also be produced. The prior art lost circulation materials describe cellulose-based particles in which hydrogen bonds are formed between cellulose particles by an aqueous medium.

When applied in a drilling fluid, the third component may have adhesive properties to the first component and/or the second component. The third component may have a tangential modulus of elasticity Et generally less than 1/10 for the longitudinal modulus of elasticity El and a radial modulus of elasticity Er generally less than 1/5 for El. A material with such mechanical properties can be formed into suitable anisotropic particles by a simple milling process, since the less strong dimensions will be milled more. Such material may be, for example, an organic or vegetable based material containing cellulose, typically wood. For example, the longest dimension of the particles of the third component may be more than three times the shortest dimension of the particles in a direction perpendicular to the direction of the longest dimension. In this way, the particles of the third component will extend through a relatively long length within the membrane, thereby providing greater strength.

The preparation of the components can be carried out in different ways in order to achieve special effects and to reduce the energy consumption in the process. For example, the material may be machined with different grinders or hammers to produce the desired size and shape to produce the functionality of the material. Heat treatment or calcination of the material before or after grinding may affect the components to achieve specific properties in the drilling fluid, thereby achieving the properties. Freeze drying the components prior to comminution may result in high quality particles. The original shape of the particles can be maintained and no disadvantages of the freeze-drying process are found in the rehydrated particles. Freeze-drying may be particularly advantageous for the processing and preservation of natural fibrous materials, and it may have the additional advantage that bacteria are not transferred into the final composition.

The composition may for example comprise 15-99% of the first component, e.g. 40-95%, and 1-30% of the second component, e.g. 5-25%. It has been found that such concentrations of the first and second components provide good film forming properties when used in a drilling fluid. The composition may for example comprise up to 80%, such as up to 40%, of the third component.

Rheological measurements obtained using equipment such as the Xite 900 viscometer using API standard methods can produce misleading results when the components of the present invention are mixed into a drilling fluid. This may be due to the relative distance between the bob and the sleeve being small relative to the size of the composition used in the present invention, thereby producing an incorrect reading. However, laboratory tests have shown that the particles of the present invention are not so large as to clog the annular gap of the rheometer, however, an even larger annular gap may produce a reading more similar to the rheological behavior of the fluid as it circulates in the well. Although perhaps inaccurate, torque readings from the Heidolph Torquemaster mixer show a decrease in torque when the drilling fluid is mixed after the present invention is added to a KCl polymer drilling fluid. This further demonstrates that larger annular gaps in the viscometer can provide more realistic rheological data. This may be due to roller bearing effects or lubrication effects.

Higher concentrations of the components of the present invention can produce higher viscosity readings in the viscometer, but can still have good lubricity or roller bearing effect when applied to systems in which fluid volume or flow conditions replicate a typical well.

At least one of the first, second and/or third components may be pre-treated prior to mixing into the drilling fluid so that they will have specific properties only when the required conditions are met. For example, the particles may be pretreated so that they begin to adhere together only when they are subjected to higher pressures (e.g., above 350 bar) in the well. The mechanism may be, for example, covering the particles with a shell that will rupture and expose the untreated interior when the particles are subjected to higher stresses due to higher pressures or higher pressure differentials downhole. Thus, the particles do not stick to the equipment or the walls of the well above the well during drilling. The particles may also comprise a self-adhesive coating surface having a surface charge that allows the particles to bond to each other in the absence of a pressure differential. The particles may have a broad particle size distribution, which may allow the drilling fluid to form a continuous film on the surface, and thus pore pressure transfer is very limited.

It may be advantageous to use particles comprising natural plant fibres such as cellulose as the first component as a bridging agent, as compared to using e.g. calcium carbonate as a bridging agent. Calcium carbonate is generally a relatively brittle and incompressible inorganic mineral, and therefore it typically decomposes during circulation in the well. The size and size distribution of the calcium carbonate particles may become smaller, whereby the particles will not be able to form a seal and withstand high pressures. However, because fibers such as cellulose fibers may be flexible, highly compressible, slightly expandable, and partially extrudable, materials containing such fibers may form a fast-sealing membrane to minimize the penetration of solids into the formation. Thus, micronized fibers comprising cellulose can effectively form seals at much lower concentrations than the commonly used inorganic bleed-off loss additives. The toughness of the cellulose-containing material may improve the ability of the particles to retain the original particle size and may reduce mechanical wear and degradation, as experienced with more brittle materials.

If the particles are exposed to water in the drilling fluid, the cellulose-containing particles may naturally absorb water and swell. The presence of water can neutralize the small positive and negative charges of the cellulose, thereby entangling or interlocking the particles. In application as a non-invasive fluid product, the particles of the first, second or third component may be pressed together due to a pressure differential around the wellbore wall. During this process, water can be squeezed out and a strong film can be created by the entangled or interlocked particles. Upon removal of the water, hydrogen bridges or other types of bonds, such as covalent, van der waals or other bonds, may form between the particles, which further strengthens the membrane.

The composition may also be used in combination with clay. Clays, cellulose and natural polymers all may have small natural positive and negative charges, which, due to their dipolar nature, give rise to high affinity binding to water molecules. Such small negative and positive charges may form bonds with the cuttings or clay present in the drilling fluid. This further yields the benefit that the particles of the composition according to the invention can capture fine low gravity solids and remove them by a piggyback mechanism whereby an API 100 mesh screen is sufficient to filter out the solids. Since these particles can eliminate or reduce the need for finer screens, the conductivity of the API 100 is greatly improved compared to API 170 or 200 screens. They are widely used for leak control in almost all types of drilling fluid systems. Natural cellulosic fibers may exhibit a highly polar surface due to the presence of hydroxyl groups. The high polarity of the surface of the cellulose fibres is responsible for their hydrophilic behaviour, which may lead to fibre swelling. To further increase the interfacial bonding between the cellulose fibers, the fibers may be surface treated to improve their properties. Even with the small particle sizes described in the examples, we see that the system can seal 0.5mm or 1mm cracks when applied at the correct concentration. The treatment of the particles may be by exposure to elevated or low temperatures, mechanical comminution treatments such as hammering, cutting or grinding, or by chemical treatment. For technical applications, the surface of the particles according to the invention may be characterized by their zeta potential. For example, the maximum zeta potential of the fiber surface (which is usually present in the alkaline range) indicates their hydrophilicity or hydrophobicity. Due to the acidic surface groups, there is a linear relationship between the change in zeta potential and the water absorption capacity of the natural fibers.

The compositions of the present invention may be combined with prior art materials, prior art lost circulation materials, or well cementing materials used to produce non-invasive fluids. The composition may be particularly useful for instabilities encountered when drilling depleted reservoirs, pressurizing coal, and entering atmospheric permeable formations in the presence of high pressure formations in the same drilling sequence. The charged elements, which may be part of the material of the present invention, utilize the behavior and properties of the clay to form a final seal across the pore throat, fracture or filter cake. In fact, it may result in the use of a finely divided clay having a particle size distribution that is more impervious to water than any conventional material known to the applicant to be available today. The resulting membrane formed across the permeable zones prevents further intrusion of mud and fluids into these zones. The physical permeation of the membrane can be measured in units of fractions of a millimeter, with fluid intrusion or jet loss typically less than 20 mm. Bridging materials comprising cellulose have proven to be resilient in sealing and are less affected by recirculation and pressure differentials in the wellbore due to the flexible nature of cellulose.

The components may be treated with a natural seed oil to provide said components with an antimicrobial effect.

Testing of compositions having concentrations of 4-10lbs/bbl in drilling fluids has shown that the present invention is effective in forming films and sealing fractures and permeable formations where permeability can range from 10mDarcy to 150 Darcy.

The composition may also be combined with coarser materials, flakes, particles or fibres, where the particle size of the additional component may be e.g. 0-1000 μm or in the range of 0-10000 μm, or other coarser particle range, where coarser particles may create bridges in larger pore size fissures, and the invention is used to create fine seals or membranes towards the bridged network of coarser components.

The first and third components may be produced by processing of materials, such as those included in the following list, to achieve the desired mechanical and chemical properties and combinations thereof described for each of the components.

The following biological or biogenic materials may be suitable as the first or third component:

husks (shell), chaffs (husks) and husks (hull), e.g. almond, cashew, cocoa, coconut, coffee, oat, peanut, hickory, rice, shell or walnut nutshell

Fruits, bark, beans, pericarps, pods and seeds, for example bananas, beans, carob, neem, oranges or peas,

wood and stems, such as beech, corncobs, oak, pine, spruce or sycamore.

In a second aspect, the present invention relates to a non-invasive drilling fluid comprising a composition according to the first aspect of the invention. The non-invasive drilling fluid may be a drilling fluid, such as a solids-free drilling fluid, which is typically used to drill a reservoir portion of a wellbore. The non-invasive drilling fluid may be an oil, water or synthetic based drilling fluid and may be a weighted or unweighted drilling fluid.

In a third aspect, the present invention relates to a method for drilling a wellbore, wherein the method comprises the step of using a non-invasive drilling fluid according to the second aspect of the present invention while drilling at least a part of the wellbore. The portion may typically be a reservoir portion. Since the membranes produced by the drilling fluid comprising the composition typically cover the openings of the pores rather than block them, the membranes can be easily peeled off when the pressure on the drilling fluid is released. When drilling a hole in the reservoir portion, the pressure in the reservoir may help to remove the membrane, thereby maintaining the permeability of the reservoir portion. The method may further comprise the step of treating the portion of the wellbore with a liquid comprising sodium hypochlorite. In case parts of the film are not completely removed, such treatment may result in all or most of these parts being dissolved or dispersed again. The concentration of sodium hypochlorite can be, for example, about 5 wt%. The portion may be, for example, a reservoir portion. If a small portion of the membrane still blocks a portion of the portion, the portion of the wellbore may be treated with a hydrochloric acid solution after the step of treating the portion of the wellbore with a liquid comprising sodium hypochlorite. Any membrane portion remaining of the membrane, which may be even more, may be dissolved or dispersed therein, which is particularly advantageous for the reservoir portion of the wellbore, as permeability may be maintained. The concentration of hydrogen chloride in the hydrochloric acid may be, for example, about 16% by weight.

Aspects of the invention are described below, illustrated in the accompanying drawings, wherein:

FIG. 1a shows the composition of a typical prior art non-invasive drilling fluid without an applied pressure differential;

FIG. 1b illustrates the sealing mechanism of the prior art non-invasive drilling fluid of FIG. 1a after application of a pressure differential;

FIG. 2a shows the composition of an embodiment of the present invention dispersed in a drilling fluid prior to application of a pressure differential; and

figure 2b shows the expected sealing mechanism of the drilling fluid of figure 2a after application of a pressure differential.

Figures 1a and 1b illustrate the sealing mechanism of a typical prior art non-invasive drilling fluid 1, the non-invasive drilling fluid 1 comprising a bridging agent 2 and additional solid particles 3 from the drilling fluid. The bridging agent 2 and the solid particles 3 enter the fracture 4 in the borehole wall 5 and form a relatively tight seal 6 at the opening of the fracture 4 (as shown in figure 1 b). Some solid particles 3 enter the fracture 4. The solid particles 3 may cause additional plugging of the fractures 4, which may be undesirable in, for example, a producing zone of a well.

Fig. 2a and 2b show the intended sealing mechanism of an embodiment of the composition according to the invention. The composition comprises particles of a first component 7, a second component 8 and a third component 9. The three component particles interlock to form a film 10 (shown in figure 2 b) across the fracture 4. The particles of the first component 7 act as a bridging agent, the deformable particles of the second component 8 deform to seal the pores, and the particles of the third component 9 interlock with other particles of the drilling fluid to provide strength and resilience to the membrane 10. The resulting membrane 10 is thus fluid-tight, flexible and able to withstand much higher pressures than the non-invasive fluids of the prior art. Further, the resulting film 10 can be produced in the absence of drilling solids or weighting materials.

Detailed Description

Examples of preferred embodiments of the invention are described below.

One method of mixing the components prior to adding them to the drilling fluid is to mix them in a ribbon mixer. Another way of mixing the components is air mixing.

In examples 1 to 3, reference to, for example, 80 mesh should be understood as grinding the components to a size that can pass through an 80 mesh dry screen.

In the examples, a water-based solids-free mud was prepared containing: soda ash, caustic soda, xanthan gum, low viscosity polyanionic cellulose (PAC LV), KCl. The slurry was mixed for 1 hour and set aside.

Example 1: non-invasive drilling fluid composition 1 was added to a water-based fluid, where the following components were ground, dried and sieved:

almond shell powder (100 mesh): 75% (component one)

Tamarind seed powder (100 mesh): 25% (component two)

Example 2: non-invasive drilling fluid composition 2 was added to a water-based fluid, where the following components were ground, dried and sieved:

almond shell powder (100 mesh): 75% (component one)

Tamarind seed powder (100 mesh): 5% (component two)

Coffee shell (120 mesh): 20% (three components)

Example 3: non-invasive drilling fluid composition 3 was added to the water-based fluid, where the following components were ground, dried and sieved:

almond shell powder (100 mesh): 90% (component one)

Acid soybean seed powder (100 mesh): 10% (component two)

Table 1: examples 1 to 3 important properties of the drilling fluids. BHR is before hot rolling and AHR is after hot rolling.

Example 4: leakage loss and rheology testing

Sand bed tests were carried out to establish a test having different test additives, additive A (composition according to the invention) and additive B (registered trade marks)

) Relative testing for leakage loss of base fluid. With reference to a slurry without any additives, additive A at a concentration of 10lbs/bbl is a composition according to the invention, 10lbs/bbl concentratedAdditive B of degree is NIF of conventional drilling, NC is uncontrolled.

Water-based solids free muds were prepared as described above. The filter cylinder was filled to 45mm with 20/40 mesh fraction sand. 118g of the slurry to be tested was covered on the cell, covered and slowly pressurized at 100 psi. The filtrate invades the sand for a short period of time and then stops completely, allowing the bottom of the sand bed to dry. The depth of penetration is reported in mm and the results are shown in Table 2.

Another set of tests was performed using water-based bentonite slurries. These results are given in table 3.

Table 2: performance testing in solids free slurries

Table 3: performance testing in 8.7ppg (pound/gallon) bentonite mud

Example 5: acid degradability

The acid solubility was tested with two additives, additive a and additive B. The test additives were tested by placing them in 16% HCl and 16% HCl + 5% Na₂S₂O₈The acid solubility was tested by adding to the solution and heating at 90 ℃ for 8 hours. The test additive was filtered and the solids collected on the filter paper were weighed. The percentage of solubility was measured.

Table 4: percent solubility

Example 6: complete dissolution was achieved by double treatment: treated with 5% NaOCl solution at 90 ℃ for 3 hours and then with 16% HCl solution at 90 ℃ for 3 hours.

Table 5: percent solubility

This example shows that a drilling fluid containing additive a can seal sand beds in the absence of drilling solids or other solids (e.g., bentonite in mud). This will enable drilling of a reservoir, e.g. containing hydrocarbons, without allowing large amounts of drilling solids or other solids to enter the formation, which may reduce the natural permeability of the reservoir after drilling is completed. In addition, the recorded film solubility will allow removal of the film by back pressure or dissolution prior to production.

It should be noted that the above-mentioned embodiments illustrate rather than limit the invention, and that those skilled in the art will be able to design many alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. Use of the verb "comprise" and its conjugations does not exclude the presence of elements or steps other than those stated in a claim. The article "a" or "an" preceding an element does not exclude the presence of a plurality of such elements.

Claims

1. A composition for rendering a drilling fluid non-invasive, the composition comprising:

-a first component comprising particles having a scratch hardness higher than 2 Mohs; and

-a second component comprising particles selected from crushed tamarind seed, crushed litsea glutinosa bark or crushed microcystis macrocarpa.

2. The composition of claim 1, wherein the composition further comprises a third biogenic component having anisotropic mechanical properties or shape and an elastic modulus greater than 2000MPa and less than 40000 MPa.

3. The composition of claim 1 or 2, wherein the size and shape of the components allow the particles to pass through a dry sieve having a 60 mesh screen.

4. The composition of any one of the preceding claims, wherein the particles of the composition are of biological origin.

5. The composition of any of the preceding claims, wherein the concentration of the first component is 15-99 wt%, the concentration of the second component is 1-30 wt%, and the concentration of the third component is 0-80 wt%.

6. A non-invasive drilling fluid comprising the composition according to any of the preceding claims, wherein the total concentration of components is less than 30 pounds per barrel, corresponding to 85.5kg/m³。

7. The non-invasive drilling fluid according to claim 6 wherein the total concentration of components is 4-10 pounds per barrel, corresponding to 11.4-28.5kg/m³。

8. The non-invasive drilling fluid according to claim 6 or 7, wherein the drilling fluid is a solids-free drilling fluid that does not require drill cuttings or contains additional solids as weighting or bridging agents to make the fluid a non-invasive fluid.

9. A method of drilling a wellbore, comprising the step of using the non-invasive drilling fluid of any of claims 6-8 while drilling at least a portion of the wellbore.

10. The method of claim 9, further comprising the step of treating the portion of the wellbore with a liquid comprising sodium hypochlorite.