WO2010126925A2

WO2010126925A2 - Wellbore fluids employing sacrificial viscosifiers

Info

Publication number: WO2010126925A2
Application number: PCT/US2010/032649
Authority: WO
Inventors: Mike Rafferty; Mike Williford
Original assignee: M-I L.L.C.
Priority date: 2009-04-29
Filing date: 2010-04-28
Publication date: 2010-11-04
Also published as: WO2010126925A3

Abstract

A method of transporting a wellbore fluid that includes transporting a wellbore fluid to a storage tank, wherein the wellbore fluid comprises: a base fluid; a sacrificial polymer; and a weighting agent; and adding a degradation agent to the wellbore fluid to degrade the sacrificial polymer is disclosed.

Description

WELLBORE FLUIDS EMPLOYING SACRIFICIAL VISCOSIFIERS

BACKGROUND

Field of the Disclosure

[0001] Embodiments disclosed herein relate generally to wellbore fluids having polymeric viscosifers therein. In other aspects, embodiments disclosed herein relate to wellbore fluids having increased viscosity during transport of the wellbore fluid, and reduced viscosity while drilling.

Background

[0002] When drilling wells in earth formations, various fluids typically are used in the well for a variety of reasons. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling, transportation of "cuttings" (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.

[0003] There are a number of different types of conventional drilling fluids including compositions termed "drilling muds." Drilling muds comprise high-density dispersions of fine solids in an aqueous or oleaginous liquid. Selection between water and oil-based fluids typically depends on the particular application. For example, in riserless drilling, because the drilling fluid is not circulated back to the rig, seawater alone, or blends of sea water with drilling muds are used. Additionally, mud additives may be employed to improve fluid properties. In general during drilling operations, wellbore fluids should be pumpable under pressure down through strings of drill pipe, through and around the drill bit, and through the annulus between the outside of the drill stem and the hole wall or casing. Beyond providing drilling lubrication and efficiency, and retarding wear, drilling fluids should suspend and transport solid drill cuttings to the surface for separation and disposal. In addition, the fluids should be capable of suspending additive weighting agents (to increase specific gravity of the mud), generally finely ground barites (barium sulfate), which are used to balance the well's natural pressure. Thus, drilling fluids are designed to have sufficient viscosity for such suspension and/or carrying capacity of solid particles.

[0004] Drilling fluids are generally characterized as thixotropic fluid systems. That is, they exhibit low viscosity when sheared, such as when in circulation (as occurs during pumping or contact with the moving drill bit). However, when the shearing action is halted, the fluid should be capable of suspending the solids it contains to prevent gravity separation. In addition, when the drilling fluid is under shear conditions and a free-flowing near-liquid, it must retain a sufficiently high enough viscosity to carry all particulate matter from the bottom of the wellbore to the surface or seafloor.

[0005] There also exist increasing needs for drilling fluids having the rheological profiles that enable wells, especially deep or horizontal wells, to be drilled more easily. Drilling fluids having tailored rheological properties ensure that cuttings are removed from the wellbore as efficiently and effectively as possible to avoid the formation of cuttings beds in the well which can cause the drill string to become stuck, among other issues. From a drilling fluid hydraulics perspective (equivalent circulating density), there exist a need to reduce the pressures required to circulate the fluid, to help avoid exposing the formation to excessive forces that can fracture the formation causing the fluid, and possibly the well, to be lost. In addition, an enhanced profile is necessary to prevent settlement or sag of the weighting agent in the fluid, if this occurs it can lead to an uneven density profile within the circulating fluid system, which can result in loss of well control, such as due to gas/fluid influx, and wellbore stability problems, such as caving and fractures.

[0006] Fluid characteristics required to meet these challenges include, for instance, that the fluid must be easy to pump, requiring only the minimum amount of pressure to force the fluid through restrictions in the circulating fluid system, such as bit nozzles or down-hole tools. In other words, the fluid should have the lowest possible viscosity under high shear conditions. Conversely, in zones of the well where the flow area is large, velocity of the fluid is low, where there are low shear conditions, or when the fluid is static, the viscosity of the fluid should be as high as possible in order to prevent settlement, suspend, and transport the weighting material and drilled cuttings. However, it should also be noted that the viscosity of the fluid should not continue to increase under static conditions to unacceptable levels. Otherwise, when fluid circulation is regained, this can lead to excessive pressures that can fracture the formation or alternatively can lead to lost time if the force required to regain a fully circulating fluid system is beyond the limits of the pumps.

[0007] Wellbore fluids must also contribute to the stability of the wellbore, and control the flow of gas, oil or water from the pores of the formation in order to prevent, for example, the flow or blow out of formation fluids or the collapse of pressured earth formations. The column of fluid in the hole exerts a hydrostatic pressure proportional to the depth of the hole and the density of the fluid. High- pressure formations may require a fluid with a specific gravity of 3.0 or higher.

[0008] A variety of materials are presently used to increase the density and rheological profile of wellbore fluids. These include dissolved salts such as sodium chloride, calcium chloride, and calcium bromide. Alternatively, powdered minerals such as barite, calcite and hematite are added to a fluid to form a suspension of increased density. Further, materials such as polymers, hydrating clays, and salt solutions are used to improve inhibition, density, viscosity, and other rheological properties of drilling fluids.

[0009] Being able to formulate a drilling fluid having a high density and a low plastic viscosity is also important in deep high pressure wells where high-density wellbore fluids are required. High viscosities can result in an increase in pressure at the bottom of the hole under pumping conditions. This increase in "Equivalent Circulating Density" can result in opening fractures in the formation, and serious losses of the wellbore fluid into the fractured formation. Again the stability of the suspension is important in order to maintain the hydrostatic head to avoid a blow out. The goal of high-density fluids with low viscosity plus minimal sag of weighting material continues to be a challenge.

[0010] Accordingly, there exists a continuing need for wellbore fluids having rheological properties favorable in reducing potential problems and increasing drilling time. SUMMARY OF DISCLOSURE

[0011] In one aspect, embodiments disclosed herein relate to a method of transporting a wellbore fluid that includes transporting a wellbore fluid to a storage tank, wherein the wellbore fluid comprises: a base fluid; a sacrificial polymer; and a weighting agent; and adding a degradation agent to the wellbore fluid to degrade the sacrificial polymer.

[0012] In another aspect, embodiments disclosed herein relate to a method of pumping a wellbore fluid that includes pumping a wellbore fluid to a drilling assembly for drilling a borehole on a seafloor, the drilling assembly comprising a drill string and bottomhole assembly, wherein the wellbore fluid comprises: a base fluid; a sacrificial polymer; a weighting agent; and a degradation agent; and triggering degradation of the sacrificial polymer by the degradation agent in the wellbore fluid before the wellbore fluid exits the bottomhole assembly.

[0013] Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

[0014] FIG. 1 is a schematic view of open hole drilling according to one embodiment disclosed herein.

DETAILED DESCRIPTION

[0015] In one aspect, embodiments disclosed herein relate to methods of transporting wellbore fluids and methods of pumping these fluids to a drilling assembly for drilling a borehole on a seafloor. In particular, embodiments disclosed herein relate to wellbore fluids useful in drilling a section of a borehole without a riser. Such fluids may include an aqueous base fluid, a sacrificial polymer, a weighting agent, and a degradation agent.

[0016] During transport of wellbore fluids, a viscosifier may be provided in the fluid formulation for suspension of weight material and other solid particles in the fluid. If the fluid does not maintain suspension of its solid particles by the viscosifier, these particles may drop or deposit onto the bottom of a rig tank or the transfer storage tank resulting in a lower fluid weight. However, the viscosity of drilling fluids greatly affects the rate of penetration of the drill bit when drilling. Thus, while it may be necessary to ensure adequate suspension of solid particles to have an adequately weighted fluid pumped downhole, the presence of the viscosifers may cause reduced rates of penetration, and may have a significant impact on drilling time, particularly when drilling riserless. Formulation of a wellbore fluid with a sacrificial polymer (i.e., a polymer that is later degraded), and a weighting agent may allow for sufficient viscosity when necessary to reduce sedimentation of weighting agents during transport, while when used in drilling riserless, the viscosity of the drilling fluid may be reduced by degrading the sacrificial polymer before the fluid exits the drill bit.

[0017] Sacrificial Polymers

As disclosed herein, the sacrificial polymer may be used during the transport of wellbore fluids to impart viscosity to the fluid. As used herein, "sacrificial polymer" is defined as a polymeric viscosifϊer used to suspend weighting agents and other solid particles during transport of wellbore fluid but which is degraded prior to use downhole. For example, the sacrificial polymer may include viscosifiers such as polysaccharides or polysaccharide derivatives. Some representative polymers are discussed in U.S. Patent No. 4,846,981 and the references cited therein, all of which are hereby incorporated by reference.

[0018] Exemplary polysaccharide polymers may include starch derivatives, cellulose derivatives, and biopolymers, such as: hydroxypropyl starch, hydroxyethyl starch, carboxymethyl starch, and their corresponding lightly crosslinked derivatives; carboxymethyl cellulose, hydroxyethyl cellulose, hydroxypropyl cellulose, methyl cellulose, dihydroxypropyl cellulose, and their corresponding lightly crosslinked derivatives; xanthan gum, gellan gum, welan gum, and schleroglucan gum. However, this list is not exhaustive. Further, one skilled in the art would appreciate that other types of polymers may be used to impart the desired viscosity but are also degradable with the types of degradation agents disclosed herein.

[0019] Thus, fluids may be provided with a sacrificial polymer for transportation of the fluid and maintaining suspension of weighting agents in the fluid during transportation. In offshore drilling, upon arrival of the wellbore fluid to the drilling location, the fluid may be transferred to a tank upon the floating vessel for pumping downhole. However, before or during pumping, the viscosity of the wellbore fluid may be reduced by the addition of a degradation agent to the fluid to allow for such higher rates of penetration discussed herein. Alternatively, a delayed degradation agent may be provided in the fluid, and the degradation agent may be activated by a triggering mechanism during pumping to reduce the viscosity of the wellbore fluid just before exiting the drill bit.

[0020] Degradation Agent

[0021] As mentioned above, the sacrificial polymers may be degraded so that the viscosity of the fluid may decrease prior to the fluid exiting the drill bit. Degradation of sacrificial polymers contained in wellbore fluids may occur by a degradation agent. Exemplary types of degradation agents may include enzymes, oxidants, radical scavengers, caustic solutions, or other chemicals that act on defined polymeric viscosifiers (i.e., the sacrificial polymer) agents to degrade the polymeric structure. While such agents may include those specifically mentioned, one skilled in the art would appreciate that the degradation agents useful in the wellbore fluid system of the present disclosure may include any chemical agent known in the art to degrade polysaccharides or other polymeric viscosifiers to reduce the viscosity of polysaccharides-thickened fluids.

[0022] One type of degradation agent that may be used in wellbore fluids to degrade a sacrificial polymer may include alkaline or caustic agents, as these materials are typically readily available. Such an alkaline source may include caustic solution, also referred to as "sodium hydroxide" or "caustic soda." Caustic solutions may be used as pH modifying agents selected from caustic soda or similar alkali sufficient to provide an alkaline pH to reduce the viscosity of a wellbore fluid (i.e., to reduce the number of polymer chains).

[0023] Example oxidants may include peroxides (including peroxide adducts), other compounds including a peroxy bond such as persulphates, perborates, percarbonates, perphosphates, and persilicates, and other oxidizers such as hypochlorites. In a particular embodiment, a peroxide, such as magnesium peroxide, may be used as a degradation agent in the wellbore fluid of the present disclosure. Additional peroxides that may be used include those discussed in U. S. Patent No. 6,861,394, which is assigned to the present assignee and herein incorporated by reference in its entirety. Effective concentrations of the oxidant may range from about 0.5 lb/bbl to about 50 lbs/bbl, preferably from about 2 lb/bbl to about 48 lbs/bbl. However, one of ordinary skill in the art would appreciate that the amount of oxidant in a particular fluid may depend, for example, on the type (and strength) of oxidant used as well as the type and the amount of the polymer being degraded.

[0024] Another class of degradation agents suitable for use in the fluids of the present disclosure may include enzymes. Enzymes are a class of proteins that are responsible for catalyzing almost every chemical reaction that occurs in nature. As nature catalysts, enzymes are usually only active within a range of conditions, particularly pH, temperature, and aqueous solvents. It is for this reason that enzyme degradation agents have been disclosed, in patents such as U.S. Pat. No. 6,861,394 to Ballard et al., and U.S. Pat. No. 6,818,594, both of which are assigned to the present assignee and herein incorporated in their entirety.

[0025] A wide variety of enzymes have been identified and separately classified according to their characteristics. A detailed description and classification of known enzymes is provided in the reference entitled ENZYME NOMENCLATURE (1984): RECOMMENDATIONS OF THE NOMENCLATURE COMMITTEE OF THE INTERNATIONAL UNION OF BIOCHEMISTRY ON THE NOMENCLATURE AND CLASSIFICATION OF ENZYME-CATALYSED REACTIONS (Academic Press 1984) [hereinafter referred to as "Enzyme Nomenclature (1984)"], the disclosure of which is fully incorporated by reference herein. According to Enzyme Nomenclature (1984), enzymes can be divided into six classes, namely (1) Oxidoreductases, (2) Transferases, (3) Hydrolases, (4) Lyases, (5) Isomerases, and (6) Ligases. Each class is further divided into subclasses by action, etc. Although each class may include one or more enzymes that will degrade one or more polymeric additives present in a wellbore fluid (and thus filter cake), the classes of enzymes in accordance with Enzyme Nomenclature (1984) most useful in the methods of the present invention are (3) Hydrolases, (4) Lyases, (2) Transferases, and (1) Oxidoreductases. Of these, enzymes of classes (3) and (4) may be the most applicable to the present disclosure.

[0026] Further, one skilled in the art would appreciate that selection of an enzyme may depend on various factors such as the type of polymeric additive used in the wellbore fluid being degraded, for example, carboxymethylcellulose, hydroxyethylcellulose, guar, xanthan, glucans and starch, the temperature of the wellbore, and the pH of the drilling environment. In particular embodiments, endo- amylase, exo-amylase, isomylase, glucosidase, amylo-glucosidase, malto-hydrolase, maltosidase, isomalto-hydro-lase or malto-hexaosidase may be used as the degradation agent in the wellbore fluids of the present disclosure. Such enzymes may be present in an amount ranging from 1 to 10 weight percent of the fluid.

[0027] Although optional, free radical scavengers or reducing agents may be added to wellbore fluids of the present invention. These materials may enhance the stability of the fluid and aid in avoiding premature degradation of the polysaccharide or other sacrificial polymer in the wellbore fluid. Representative reducing agents are water soluble sulfites, bisulfites, thiosulfates, dithionites, and mixtures thereof, preferably a water soluble thiosulfate, most preferably sodium thiosulfate. Representative antioxidants or free radical scavengers include water soluble mercaptans, thioethers, thiocarbonyls, low molecular weight alcohols and glycols, and mixtures thereof.

[0028] As described above, the degradation agents may be added to the wellbore when reduction of viscosity is desired, or alternatively, the degradation agent may contain a delay mechanism whereby it does not release or degrade the sacrificial polymer until a triggering signal is applied. Thus, the fluid may initially be formulated with an inactive delayed degradation agent and be pumped down a drill string concurrently with a triggering source concurrently with the wellbore fluid to begin the degradation of the sacrificial polymer as the fluid travels down the drillstring. One example of a delay mechanism to render the degradation agent inactive is encapsulation, such as a polymeric capsule impermeable to the degradation agent. Another such encapsulation may include a semi-permeable nylon shell. One skilled in the art would appreciate that various materials and techniques for encapsulating compounds under conditions compatibility are available, as such as those disclosed in U.S. Patent No. 6,818,594 assigned to the present assignee and herein incorporated by reference in its entirety. Certain embodiments of the present disclosure may use oxidants or enzymes that have been encapsulated to provide a delay mechanism for the degradation agent. For the purposes of the present disclosure, an encapsulated oxidant (or enzyme) is an oxidant (enzyme) that has a coating sufficient to control the release of oxidant (enzyme) until a set of conditions selected by the operator occurs. Some general encapsulating materials may include natural and synthetic oils, natural and synthetic polymers, and mixtures thereof. However, many methods of encapsulating may alternatively be used without departing from the scope of the present disclosure.

[0029] Many methods may be used to cause or trigger the release of an encapsulated oxidant or enzyme upon the occurrence of specific conditions desired by the operator. For example, the triggered release of an encapsulated degradation agent may be caused by a change in temperature, pressure, pH, abrasion, or any number of these or other environmental factors. In a particular embodiment, the method by which the degradation agent is released from encapsulation for the purposes of degrading a polymer may be upon a change in pH.

[0030] Further, while a simple addition of an acid or base may trigger release of encapsulated degradation agent (i.e., to degrade the sacrificial polymer), in particular embodiments where further delay is required, a delayed acid source may be used, for example. The delayed acid source may include compounds which may release acid upon a length of time. In particular, compounds that hydrolyze to form acids in situ may be utilized as a delayed acid source. Such delayed sources of acidity may be provided, for example, by hydrolysis of an ester. Illustrative examples of such delayed acid sources include hydrolysable anhydrides of carboxylic acids, hydrolysable esters of carboxylic acids; hydrolysable esters of phosphonic acid, hydrolysable esters of sulfonic acid and other similar hydrolysable compounds that should be well known to those skilled in the art.

[0031] Weighting Agent

[0032] The density of a wellbore fluid contributes to the stability of the borehole by increasing the pressure exerted by the wellbore fluid onto the formation downhole. The column of fluid in the borehole exerts a hydrostatic pressure (also known as head pressure) proportional to the depth of the hole and the density of the fluid. Therefore, one can stabilize the borehole and prevent the undesirable inflow of reservoir fluids by carefully monitoring the density of the wellbore fluid to ensure that an adequate amount of hydrostatic pressure is maintained. [0033] A variety of methods exist to increase the density of wellbore fluids. One method may include adding dissolved salts such as sodium chloride, calcium chloride, and calcium bromide in the form of an aqueous brine to wellbore fluids. Another method is adding inert, high-density particulates to wellbore fluids to form a suspension of increased density. These^* inert, high-density particulates often are referred to as "weighting agents" and typically include powdered minerals of barite, calcite, or hematite.

[0034] Weighting agents suitable for use in the fluids disclosed herein include, for example, galena, hematite, magnetite, iron oxides, illmenite, barite, siderite, celestite, dolomite, calcite, and the like. The quantity of such material added, if any, depends upon the desired density of the final composition. Typically, weight material is added to result in a drilling fluid density of up to about 19 pounds per gallon in one embodiment, and ranging from 9.5 to 14 pounds per gallon in another embodiment.

[0035] The weighting agent may be formed of particles that are composed of a material of specific gravity of at least 2.3; at least 2.4 in other embodiments; at least 2.5 in other embodiments; at least 2.6 in other embodiments; and at least 2.68 in yet other embodiments. For example, a weighting agent formed of particles having a specific gravity of at least 2.68 may allow wellbore fluids to be formulated to meet most density requirements yet have a particulate volume fraction low enough for the fluid to be pumpable. For a high density fluid, the weighting agent may be formed of solid particles that are composed of a material having a specific gravity of at least 4.2. However, one skilled in the art would appreciate that selection of a specific gravity may be based on density needs for a particular application, and therefore no limitation is placed on the fluids of the present disclosure. Moreover, selection of a type of material may be based, for example, on the specific density required.

[0036] Naturally occurring barite (barium sulfate) has been utilized as a weighting agent in drilling fluids for many years. Drilling grade barite is often produced from barium sulfate containing ores either from a single source or by blending material from several sources. It may contain additional materials other than barium sulfate mineral and thus may vary in color from off-white to grey or red brown. The American Petroleum Institute (API) has issued international standards to which ground barite must comply. These standards can be found in API Specification 13 A, Section 2. Conventional API grade weighting agents such as powdered barites ("barite") exhibit an average particle diameter (d₅o) in the range of 10-30 μm.

[0037] In addition to API grades of weighting agents, the weighting agents may also include sized or micronized weighting agents, such as those disclosed in U.S. Patent Nos. 7,220,707, 6,586,372, 7,267291, 7,176,165, and 7,169,738, all of which are assigned to the present assignee and herein incorporated by reference in their entirety. A sized weighting agent may be used when an increased density with improved suspension stability without significant viscosity increase is desired. Such an embodiment may utilize barite particles ground (or otherwise formed) to a particle size distribution such that at least 90% of the cumulative volume of the measured particle diameters (d9o) is between about 4μm and about 20 μm and at least 50% of the cumulative volume of the measured particle diameters (d₅₀) is preferably in the range of about lμm to about 10 μm. And in another embodiment, the weighting agent includes at least 90% by weight particles in the range of about 4μm to about 8μm. Such a wellbore fluid may exhibit a reduced viscosity while also having at the same time increased rates of penetration of the drill bit and reduced sedimentation or sag as compared to conventional wellbore fluids.

[0038] Thus, as disclosed herein, the weighting agent used may include both API grade barite and micronized barite, and the selection between standard API grade and micronized barite may depend on factors such as lost circulation, availability, or other known events in the industry. In particular in the preferred embodiment, micronized barite may be used for reduction of sag and settlement of weight material.

[0039] Base Fluid

[0040] Drilling fluids are typically classified according to their base fluid. In water- based fluids, solid particles are suspended in a continuous phase of water or brine, or other non-oleaginous fluid, and oil may be optionally emulsified in the water. As used herein, "non-oleaginous" is defined as aqueous substances such as fresh water, seawater, brine containing inorganic or organic dissolved salts, aqueous solutions containing water-miscible organic compounds, and mixtures thereof. In various embodiments of the drilling fluid disclosed herein, the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of seawater. The salinity of seawater may range from about 1 percent to about 4.2 percent salt by weight based on total volume of seawater. Salts that may be found in seawater include, but are not limited to, sodium, calcium, sulfur, aluminum, magnesium, potassium, strontium, lithium, and salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, phosphates, silicates and fluorides. Salts that may be incorporated into brine include any of one or more of those present in natural seawater or any other organic or inorganic dissolved salts.

[0041] Additionally, brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in construction. In one embodiment, the density of the drilling fluid may be controlled at least partially by increasing the salt concentration in the brine (up to saturation). In a particular embodiment, a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium.

[0042] The pH of these solutions is preferably between about 7 to about 12, even more preferably between about 7.5 to about 10.5. The pH can be adjusted by methods known to those skilled in the art, including the addition of bases to the fluids. Such bases include potassium hydroxide, sodium hydroxide, magnesium oxide, calcium hydroxide, and zinc oxide. These aqueous fluids are generally brine solutions.

[0043] Methods of Use

[0044] The fluids of the present disclosure may be used in drilling any type of wellbore; however, in particular embodiments, the fluids may be particularly suitable for use in riserless drilling. Thus, a fluid may be formulated with a sacrificial polymer to aid in suspension of solid particles in the fluid during transport of the fluid to the wellsite. Prior to, or as a fluid is pumped into a wellbore to aid in drilling and removing cuttings from the wellbore, the sacrificial polymers initially formulated in the fluid may be degraded to reduce the viscosity of the fluid and thus allow for increased rates of penetration during drilling.

[0045] As mentioned above, the fluids may be used to drill any section of a wellbore, but in a particular embodiment, the fluids may be used to drill an initial section of a wellbore in an offshore operation that is typically drilled riserless or open hole. Referring to FIG. 1 , a schematic of an open-hole wellbore is shown. As shown in FIG. 1, to drill the initial upper portion of the well 10, a drill string 14 typically extends unsupported from a vessel or platform 12 through the water to the seafloor 16 without a riser. In more detail, first an outer casing 18, known as "structural casing," typically having a diameter of up to 30-inches or 36-inches, is installed in the uppermost section of the well, with a low-pressure wellhead housing (not shown separately) connected thereto. In soft formations, the structural casing 18 may be jetted into place. In this process, a drilling assembly that includes the drill string 14 and a bottom hole assembly (BHA) (not shown separately), and casing 20 is lowered to the seafloor via the drill string 14. The BHA includes a drill bit 16, and may also include other components such as, drill collars and a downhole motor (not shown separately). The bit 16 is positioned just below the bottom end of the structural casing 20 and is sized to drill a borehole 22 with a slightly smaller diameter than the diameter of the casing 20. As the borehole 22 is drilled, the structural casing 20 moves downwardly with the BHA. The weight of the structural casing 20 and BHA drives the casing 20 into the sediments. The structural casing 20, in its final position, may extend downwardly to a depth of 150 to 400 feet, depending upon the formation conditions and the final well design. After the structural casing 20 is in place, it may be released from the drill string 14 and BHA. The drill string 14 and BHA may be tripped back to the platform, or alternatively, may be lowered to drill below the structural casing.

[0046] Alternatively, the structural casing 20 may be installed in a two-step process.

First, a borehole larger than the structural casing is drilled. Then the structural casing 20 is run into the borehole 22 and cemented into place. Typically, the low-pressure wellhead housing (not shown separately) is connected to the upper end of the structural casing 20 and installed at the same time, such that the structural casing 20 extends below the seafloor with the low-pressure wellhead housing above the seafloor.

[0047] Once the structural casing 20 and the low-pressure wellhead housing are installed, the bit 16 on the drill string 14 drills downwardly below the structural casing 20 to drill a new borehole section using open hole drilling for an intermediate casing 24, known as "conductor casing," which may be, for example, 20-inches in diameter. Thus, the structural casing 20 guides the BHA as it begins to drill the conductor casing 24 interval. After the borehole section for the conductor casing 24 is drilled, the BHA is tripped to the surface. Then conductor casing 24, with a high- pressure wellhead housing connected to its upper end, and a float valve disposed in its lower end (not shown separately), is run into the drilled conductor borehole section extending below the structural casing 20. The conductor casing 24 is cemented into place in a well known manner, with the float valve preventing cement from flowing upwardly into the conductor casing after cement placement. The conductor casing 24 generally may extend downwardly to a depth of 1,000 to 3,000 feet below the seafloor, depending on the formation conditions and the final well design. The high- pressure wellhead housing (not shown separately) may engage the low-pressure wellhead housing (not shown separately) to form the subsea wellhead, thereby completing the riserless portion of the drilling operations. Installation of a subsea blowout preventer (BOP) stack may be conveyed down to the seafloor by a riser and latched onto the subsea wellhead housing for subsequent riser drilling.

[0048] During the open hole drilling shown in FIG. 1 , drilling fluid flows through the drill string 14 and out of the drill bit 16 as shown by downward arrows 26. The flow of the drilling fluid continues through the annulus between the borehole 22 and the drilling assembly 14, 16. As the drilling fluid flows through this annulus, it may carry drilled cuttings through the borehole, indicated by upward arrows 28 and may exit the well to be dispersed into the sea, as indicated by arrows 30. Therefore, in open hole drilling the returns, i.e. the drilling fluid, cuttings, and well fluids, are discharged onto the seafloor and are not conveyed to the surface. Further, while an open hole well is shown, one skilled in the art would appreciate that the methods and fluids of the present disclosure are not limited as such. Rather such fluids may be used in any wellbore, and the methods of transporting the fluids of the present disclosure may similarly be used in combination with drilling any type of wellbore.

[0049] Advantageously, embodiments disclosed herein may provide fluids formulated with a sacrificial polymer. Such fluids may be particularly suitable as a drilling fluid that may be used in open hole drilling, whereby the wellbore fluids disclosed herein may further provide the rheological properties needed for drilling without a riser. However, the sacrificial polymer may be provided in the initial formulation to maintain suspension of weighting agents during transport, but may be thereafter degraded such that the fluid's viscosity is reduced during pumping operations to thereby increase the rates of penetration of the drill bit. While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

CLAIMSWhat is claimed:

1. A method of transporting a wellbore fluid, comprising: transporting a wellbore fluid to a storage tank, wherein the wellbore fluid comprises: a base fluid; a sacrificial polymer; and a weighting agent; and adding a degradation agent to the wellbore fluid to degrade the sacrificial polymer.

2. The method of claim 1, wherein the sacrificial polymer is selected from guar gum, xanthan gum, scleroglucan, carboxymethyl cellulose, hydroxyethyl cellulose, sodium salt of carboxy-methylcellulose, modified starches, phosphomannans, glucans, dextrane, and combinations therefrom.

3. The method of claim 1, wherein the base fluid is an non-oleaginous fluid selected from freshwater, seawater, saltwater, brine, or combinations thereof.

4. The method of claim 1, wherein the weighting agent is a conventional API grade weighting agent selected from barite, calcium carbonate, hematite, ilmenite, dolomite, siderite, strontium sulfate, or combinations therefrom.

5. The method of claim 1, wherein the weighting agent is a micronized weighting agent selected from barite, calcium carbonate, hematite, ilmenite, dolomite, siderite, strontium sulfate, or combinations therefrom.

6. The method of claim 1, wherein the storage tank is disposed on a floating vessel.

7. The method of claim 1, wherein the sacrificial polymer to the wellbore fluid suspends the weighting agent during transport of the wellbore fluid.

8. The method of claim 1, wherein the degradation agent comprises at least one selected from enzymes, oxidants, radical scavengers, caustic solutions, and combinations thereof.

9. The method of claim 1, wherein the degradation agent triggers an increase in the pH value of the wellbore fluid to greater than about 10.5.

10. A method of pumping a wellbore fluid, comprising: pumping a wellbore fluid to a drilling assembly for drilling a borehole on a seafloor, the drilling assembly comprising a drill string and bottomhole assembly, wherein the wellbore fluid comprises: a base fluid; a sacrificial polymer; a weighting agent; and a degradation agent; and triggering degradation of the sacrificial polymer by the degradation agent in the wellbore fluid before the wellbore fluid exits the bottomhole assembly.

11. The method of claim 10, wherein the base fluid is an non-oleaginous fluid selected from freshwater, seawater, saltwater, brine, or combinations thereof.

12. The method of claim 10, wherein the sacrificial polymer is selected from guar gum, xanthan gum, scleroglucan, carboxymethyl cellulose, hydroxyethyl cellulose, sodium salt of carboxy-methylcellulose, modified starches, phosphomannans, glucans, dextrane, and combinations therefrom.

13. The method of claim 10, wherein the weighting agent is a conventional API grade weighting agent selected from barite, calcium carbonate, hematite, ilmenite, dolomite, siderite, strontium sulfate, or combinations therefrom.

14. The method of claim 10, wherein the weighting agent is a micronized weighting agent selected from barite, calcium carbonate, hematite, ilmenite, dolomite, siderite, strontium sulfate, or combinations therefrom.

15. The method of claim 10, wherein the degradation agent comprises at least one selected from enzymes, encapsulated oxidants, non-encapsulated oxidants, radical scavengers, caustic solutions, and combinations thereof.

16. The method of claim 10, wherein the triggering mechanism comprises at least one selected from a temperature variance, pressure variance, pH variance, salinity variance, ion concentration variance, and combinations thereof.

17. The method of claim 10, wherein the degradation agent triggers an increase in the pH value of the wellbore fluid to greater than about 10.5.

18. The method of claim 10, wherein the degradation of the sacrificial polymer reduces the viscosity of the wellbore fluid.

19. The method of claim 10, further comprising: drilling the borehole with the wellbore fluid after the degradation of the sacrificial polymer, wherein drilling is characterized as having an improved rate of penetration as compared to drilling with a polymeric viscosifϊer.