WO2019217613A1

WO2019217613A1 - Insulating barrier fluid and methods thereof

Info

Publication number: WO2019217613A1
Application number: PCT/US2019/031420
Authority: WO
Inventors: Charles Svoboda; Mathieu CHAMPEAU
Original assignee: MI LLC
Current assignee: MI LLC
Priority date: 2018-05-11
Filing date: 2019-05-09
Publication date: 2019-11-14
Anticipated expiration: 2020-11-11

Abstract

A capped drilling system may include a wellbore extending through an earth formation; a drill string extending through the wellbore, terminating in a drill bit, and defining an annulus between a well of the wellbore and the drill string; a cap fluid having a density of less than 8.33 ppg in the annulus; a barrier fluid comprising an oleaginous fluid and styrenic copolymer below the cap fluid; and a drilling fluid below the barrier fluid.

Description

INSULATING BARRIER FLUID AND METHODS THEREOF

BACKGROUND

[0001] This application claims priority from U.S. Provisional Application No.

62/670,102, filed May 11, 2018, herein incorporated by reference in its entirety.

[0002] When drilling or completing wells in earth formations, various fluids 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 generally or drilling-in (i.e., drilling in a targeted petroliferous formation), 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, fracturing the formation in the vicinity of the well, 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] In conventional drilling, drilling fluids should be pumpable under pressure down through strings of the drilling pipe, then through and around the drilling bit head deep in the earth, and then returned back to the earth surface through an 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 particles to the surface for screening out 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 ore), and transport clay and other substances capable of adhering to and coating the borehole surface.

[0004] Wellbore fluids may also be used to provide sufficient hydrostatic pressure in the well to prevent the influx and efflux of formation fluids and wellbore fluids, respectively. When the pore pressure (the pressure in the formation pore space provided by the formation fluids) exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is typically maintained at a higher pressure than the pore pressure. While it is highly advantageous to maintain the wellbore pressures above the pore pressure, on the other hand, if the pressure exerted by the wellbore fluids exceeds the fracture resistance of the formation, a formation fracture and thus induced mud losses may occur. Further, with a formation fracture, when the wellbore fluid in the annulus flows into the fracture, the loss of wellbore fluid may cause the hydrostatic pressure in the wellbore to decrease, which may in turn also allow formation fluids to enter the wellbore. As a result, the formation fracture pressure typically defines an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, a major constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients through the depth of the well.

[0005] Wellbore fluids are circulated downhole to remove rock, and may deliver agents to combat the variety of issues described above. Fluid compositions may be water- or oil-based and may comprise weighting agents, surfactants, viscosifiers, fluid loss additives, and polymers. However, for a wellbore fluid to perform all of its functions and allow wellbore operations to continue, the fluid must stay in the borehole. Frequently, undesirable formation conditions are encountered in which substantial amounts or, in some cases, practically all of the wellbore fluid may be lost to the formation. For example, wellbore fluid can leave the borehole through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole.

[0006] Lost circulation is a recurring drilling problem, characterized by loss of drilling mud into downhole formations. However, in addition to drilling fluids, lost circulation may remain an issue for other wellbore fluids such as including completion, drill-in, production fluid, etc. Fluid loss can occur naturally in earthen formations that are fractured, highly permeable, porous, cavernous, or vugular. These earth formations can include shale, sands, gravel, shell beds, reef deposits, limestone, dolomite, and chalk, among others.

[0007] Lost circulation may result from induced pressure during drilling. Specifically, induced mud losses may occur when the mud weight, required for well control and to maintain a stable wellbore, exceeds the fracture resistance of the formations. A particularly challenging situation arises in depleted reservoirs, in which the drop in pore pressure weakens hydrocarbon-bearing rocks, but neighboring or inter-bedded low permeability rocks, such as shales, maintain their pore pressure. This can make the drilling of certain depleted zones impossible because the mud weight required to support the shale exceeds the fracture resistance of nearby zones composed of weakly consolidated sands and silts. Another unintentional method by which lost circulation can result is through the inability to remove low and high gravity solids from fluids. Without being able to remove such solids, the fluid density can increase, thereby increasing the hole pressure, and if such hole pressure exceeds the formation fracture pressure, fractures and fluid loss can result.

SUMMARY

[0008] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0009] In one aspect, embodiments disclosed herein relate to a capped drilling system that includes a wellbore extending through an earth formation; a drill string extending through the wellbore, terminating in a drill bit, and defining an annulus between a well of the wellbore and the drill string; a cap fluid having a density of less than 8.33 ppg in the annulus; a barrier fluid comprising an oleaginous fluid and styrenic copolymer below the cap fluid; and a drilling fluid below the barrier fluid. [0010] In another aspect, embodiments disclosed herein relate to a method of drilling a wellbore through an earth formation that includes emplacing a barrier fluid into an annulus comprising an oleaginous fluid and a styrenic copolymer; emplacing a cap fluid having a density of less than 8.33 ppg into an annulus; and emplacing a drilling fluid into the wellbore during drilling; wherein the cap fluid, the barrier fluid, and the drilling fluid are not returned to the surface during the drilling.

[0011] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

[0012] FIGs. 1 to 7 show schematics of wellbores involved in various capped drilling systems.

DETAILED DESCRIPTION

[0013] In one aspect, embodiments disclosed herein relate to capped drilling techniques and wellbore fluids used in such capped drilling. As mentioned above, during drilling operations, it can occur that large volumes of the wellbore fluids may be lost to the formation, such as due to pressure differences between the formation and the wellbore fluid. When drilling naturally fractured formations or formations that are fractured due to elevated density required for a circulating fluid, complete lost circulation may occur. Thus, while normal operations include circulating a drilling fluid through the drill string, and then up the annulus between the drill string and wellbore to the surface, as shown in FIG. 1, in lost circulation, at least a portion of the drilling fluid is lost to the formation, rather than returning to the surface. While the response to such lost circulation, in some instances, is to pump lost circulation materials, in an attempt to plug the formation, one example of an unconventional remedy is to proceed with mud cap drilling. Where no fluid returns to the surface, complete lost circulation is said to occur. In such instances, it may be possible in some cases to drill blind, as shown in FIG. 2, where all fluid pumped downhole is lost to the formation, with no returns of drilling fluid to surface. This can be successful when no formation fluids are entering the wellbore and migrating to surface.

[0014] If wellbore fluids are present and sufficiently pressurized to reach the surface, it may have health and safety concerns. To prevent wellbore fluids from reaching the surface, a fluid may be placed in the annular space to provide sufficient downhole density to control this migration. This is often generally referred to a mud cap. However, there are several types of mud caps used in the art.

[0015] If formation pressures are elevated, the mud cap may fill the complete annulus with back pressure held to keep formation fluids from migrating, as shown in FIG. 3. This is referred to a pressurized mud cap. As formation pressures decline, a complete column of fluid is not required in the annulus to control formation pressures and only a portion of the annulus is filled with fluid and an air gap is maintained above the annular fluid, as shown in FIG. 4. This is considered a floating mud cap.

[0016] As formation pressures continue to decline, some formation fluids will cease to be liquids in the formation and will exist as gas (once the pressure drops below the bubble point). These gasses will have a greater tendency to be displaced from the formation and into the wellbore as the drilling fluid is lost to the formation. As they enter the wellbore, these gasses will attempt to migrate up the annulus to surface. With a standard floating mud cap, the gas could easily migrate through this fluid as the viscosities of the mud cap and drilling fluid are not significantly different. Thus, if a gas (such as air or nitrogen) is used as part of the mud cap, formation gasses can blend or migrate through them, as shown in FIG. 5.

[0017] However, in accordance with one or more embodiments of the present disclosure, a barrier may be provided below a cap fluid and between the cap fluid and a drilling fluid being pumped into the well, as shown in FIGS 6 and 7. In particular, FIG. 6 shows a gas cap being present above the barrier fluid, and FIG. 7 shown a foamed cap being present above the barrier fluid. [0018] Thus, a low density fluid“cap” may be maintained in the well (specifically, the annulus), to reduce the overall density of the mud column in the well. In accordance with one or more embodiments of the present disclosure, such low density fluid may be maintained as the cap through the use of a barrier fluid below the low density fluid, that reduces the commingling of the flow density fluid cap (shown, for example, in FIG. 5) with the drilling fluid being pumped downhole as the drilling advances. In mud cap drilling, such drilling fluid is often water (or a similarly simple fluid) due to volume of fluid that is being lost to the formation.

[0019] In particular, generally, as the drilling fluid is pumped downhole, the circulation of the fluid and/or the convention and/or conduction of heat through the fluid would generally cause the intermingling of the drilling fluid with the mud cap, as shown in FIG. 5. However, in accordance with the present embodiments, the inclusion of the barrier fluid, such as that described herein and shown in FIGS. 6 and 7, may mitigate against just fluid intermingling. Thus, while the drilling fluid may be relatively simple in composition, the cap fluid may be designed to meet the needs of the cap drilling without significant losses of the cap fluid to the formation (due to intermingling with the drilling fluid). In particular, in one or more embodiments, the cap fluid may be a low density, low viscosity fluid, such as a fluid having a density less than water (z.e., less than 8.33 ppg equivalent mud weight). In one or more embodiments, the cap fluid may be a gas, while in one or more other embodiments, the cap fluid may be a foam (z.e., contain a gas therein, such as nitrogen or air, forming a foam) to further reduce annular pressure. Further, in one or more embodiments, the cap fluid may include a low density base oil. The selection from the above various types of cap fluids may depend, for example, on the desired density for the cap fluid. In such a manner, the overbalance pressure on the formation may be further reduced by reducing the annular hydrostatic pressure through foamed or gas cap fluid.

[0020] Below the cap fluid may be a barrier fluid of the present disclosure, which may act as an isolation device or floating piston to isolate the lower region of the well from upper regions thereof. The upper region may contain the cap fluid, and the lower region may contain the drilling fluid.

[0021] Further, because mud cap drilling is an unconventional drilling technique, it may be understood that the presently disclosed arrangement of fluids in the well may result in losses downhole. For example, upon experiencing losses to the formation (likely severe losses), the cap fluid and barrier fluid may be injected downhole. It is envisioned that the cap fluid and barrier fluid may be injected through the annulus {i.e., pumped down the backside) rather than through the drill string; however, it is also recognized that the resulting mud cap may be achieved by injecting such fluids through a drill string as well. Thus, irrespective of the manner by which the fluids are provided, they may be pumped downhole such that the cap fluid is above (i.e., closer to the surface) the barrier fluid. The drilling fluid may be below the barrier fluid. However, based on the proximity of the cap fluid and the barrier fluid, it is understood that the two fluids may be compatible with one another. Further, it is also understood that well pressures may allow the fluid barrier to“float” up or down in the annulus. In particular embodiments, the barrier fluid may be placed close to the open hole region of the wellbore, but still within the cased hole section. The cap fluid may then, for example, be pumped on top of the barrier fluid, such that the cap fluid extends from the barrier to the top of the well.

[0022] In one or more embodiments, the barrier fluid may prevent commingling of fluids by: 1) significant viscosity differential preventing a thin Newtonian drilling fluid from turbulently washing into the cap fluid while drilling, 2) avoiding any thermally induced commingling due to convective currents carrying thin warm“lighter fluids” into the colder viscous mud cap, and 3) providing a seal around the rotating and reciprocating drill string.

[0023] In one or more embodiments of the present disclosure, the barrier fluid that may be used as a barrier between the drilling fluid and mud cap fluid may be an oil-based (hydrocarbon-based) fluid, which may include styrenic copolymers, and optionally, one or more of particulates (such as precipitated silicas, organophilic clays, inorganic weighting agents) and other organic polymers such as alkyl diamides (such as those disclosed in U.S. Pat. No. 8,236,736) or oil soluble polymers (such as those sold under the trade name ECOTROL by MI SWACO (Houston, Tex.)). Such fluids may possess low thermal conductivities, increased viscosity, and high stability under elevated temperatures.

[0024] Styrenic Thermoplastic Block Copolymer

[0025] Thermoplastic elastomers are a novel class of polymers that can combine the dual characteristics of elastomers and thermoplastics. In general, it has been found that thermoplastic elastomers have a thermal degradation resistance that is related to the amount of allylic hydrogens. For example, as monomer units become more saturated, it would be expected that the thermal stability should increase. Contrary to the expectation, the thermal stability of these thermoplastic elastomers decreases with increased saturation in the presence of air in temperatures below 480 C.

[0026] The copolymer may be in various forms, such as a diblock or triblock polymer.

Further, in some embodiments, the thermoplastic elastomer may be linear, branched, star or even dendritic in structure. Comonomers may include at least one of ethylene, propylene, butylene, butadiene, or isoprene. In one or more particular embodiments, an ethylene/propylene or an ethylene/butylene block segment may be used in conjunction with the styrenic block segment. Further, it is also within the scope of the present disclosure that a tri-block polymer be used, such as a styrene-ethylene/propylene- styrene block copolymer or a styrene-ethylene/butylene-styrene block copolymer. Further, it is also within the scope of the present disclosure that one or more diene segments may be used (i.e., styrene-butadiene or styrene-butadiene-styrene), and in such embodiments, it is also within the scope of the present disclosure that the copolymer may optionally be at least partially hydrogenated.

[0027] In some embodiments, the ratio of styrene to its comonomer(s) in the thermoplastic elastomer is at least 20:80. In other embodiments, the percentage of styrene block segments is at least 25%, 30%, 35% or 40% and no more than 40%, 45%, 50%, 60%, 70%, and 80% (where any lower limit can be used with any upper limit), with the balance being the other comonomer block segments.

[0028] It will be appreciated that the arrangement of the block segments, the relative amounts of the block segments (with respect to one another), the molecular weight or length of the block segments (as well as the total molecular weight and molecular weight distribution) may affect the physical properties of the resulting copolymer, and the amount and/or placement that may be desirable for a particular wellbore application. For example, the amount of the block copolymer used in the wellbore fluids of the present disclosure may broadly range from 0.5-10 percent by weight of the fluidic portion of the fluid, and may have a lower limit of any of 0.5, 1, 2, 3, 4, or 5 weight percent, and an upper limit of any of 4, 5, 6, 7, 8, 9, or 10 weight percent, where any lower limit can be used with any upper limit. Further, the particular copolymer may have a unique Tau zero (tq), or yield stress at zero shear rate, affected by the same considerations mentioned above. In one or more embodiments, the fluid may have a Tau zero of greater than 10 at room temperature as well as at temperatures expected to be encountered in the well. However, because Tau zero may be temperature dependent, fluids having a lower Tau zero at some temperatures, but a Tau zero of at least about 10 at other temperatures may still be useful in wells that will have the temperature ranges falling within the higher Tau zero range. Further, by mixing the copolymers in with the base fluid, the oil, which would otherwise phase separate, can be gelled, preventing this phenomenon.

[0029] Solid Particulate Phase

[0030] It is also intended that one or more solid particulates may be incorporated into the fluid to provide density, viscosification, and/or prevention of top oil separation. Such particulates may include silica, inorganic weighting agents, clay particles, and the other organic viscosifiers such as alkyl diamides or oil soluble polymers.

[0031] Solid inorganic weighting agents used in some embodiments disclosed herein may include a variety of inorganic compounds well known to one of skill in the art. In some embodiments, the weighting agent may be selected from one or more of the materials including, for example, barium sulfate (barite), calcium carbonate (calcite or aragonite), dolomite, ilmenite, hematite or other iron ores, olivine, siderite, manganese oxide, and strontium sulphate. In a particular embodiment, calcium carbonate or another acid soluble solid weighting agent may be used.

[0032] For example, fumed or pyrogenic silicas useful in embodiments disclosed herein are produced from the vapor phase hydrolysis of chlorosilanes, such as silicon tetrachloride, in a hydrogen oxygen flame are non-porous, water-soluble, have low bulk density, and possess high surface area. Due to the hydrogen bonding of the surface silanol groups present on the silica particles, fumed silicas may also impart unique rheological properties, such as increased viscosity and shear-thinning behavior, when added to aqueous and emulsion fluid systems.

[0033] Another form of silica useful in embodiments of the present disclosure as a viscosifying and/or weighting agent are precipitated silicas, such as those prepared from the reaction of an alkaline silicate solution with a mineral acid. Precipitated silicas may have a porous structure, and may behave as a porous structure prepared from the reaction of an alkaline silicate solution with a mineral acid. Alkaline silicates may be selected, for example, from one or more of sodium silicate, potassium silicate, lithium silicate and quaternary ammonium silicates. Precipitated silicas may be produced by the destabilization and precipitation of silica from soluble silicates by the addition of a mineral acid and/or acidic gases. The reactants thus include an alkali metal silicate and a mineral acid, such as sulfuric acid, or an acidulating agent, such as carbon dioxide. Precipitation may be carried out under alkaline conditions, for example, by the addition of a mineral acid and an alkaline silicate solution to water with constant agitation. The properties of the silica particles may also be dependent, for example, on the choice of agitation, duration of precipitation, the addition rate of reactants, temperature, concentration, and pH.

[0034] Silicas useful in embodiments herein may include finely-divided particulate solid materials, such as powders, silts, or sands, as well as reinforced floes or agglomerates of smaller particles of siliceous material. In one or more embodiments, silica particles (or agglomerates thereof) may have an average particle size (d50) with a lower limit equal to or greater than 0.25 pm, 0.5 pm, 1 pm, 2 pm, 5 pm, 6 pm, and 8 pm to an upper limit of 5 pm, 10 pm, 15 pm, 20 pm, 40 pm, and 50 pm, where the d50 of the silica particles may range from any lower limit to any upper limit. In some embodiments, silicas having a larger initial average particle size may be used, where shear or other conditions may result in comminution, i.e., reduction of size, of the particles, such as breaking up of agglomerates, resulting in a silica particle having a useful average particle size. In yet other embodiments of the present disclosure, it is envisioned that mixtures of varying sizes of silicas may be added to various wellbore fluids.

[0035] Depending on the desired effect of the solid particulates, they may be used in an amount up to 10 weight percent of the fluid, and in one or more embodiments, may be used in an amount greater than 1, 2, 3, 5, 7, or 8 weight percent.

[0036] As mentioned, an organic viscosifier may be added to barrier fluid of the present disclosure. Such suitable viscosifier or rheological additive in accordance with embodiments of the present disclosure, for example, may include alkyl diamides, such as those having a general formula: Ri-HN-CO-(CH2)_n-CO-NH-R.2, wherein n is an integer from 1 to 20, more preferably from 1 to 4, yet more preferably from 1 to 2, and Ri is an alkyl groups having from 1 to 20 carbons, more preferably from 4 to 12 carbons, and yet more preferably from 5 to 8 carbons, and R2 is hydrogen or an alkyl group having from 1 to 20 carbons, or more preferably is hydrogen or an alkyl group having from 1 to 4 carbons, wherein Ri and R2 may or may not be identical.

[0037] Wellbore Fluid Formulation

[0038] The styrenic copolymer and optional silicas, weighting agents, etc. as described above may be combined to form an oleaginous fluid (oil-based) wellbore fluid, as outlined below. In some embodiments, the materials may be combined to form a barrier fluid in accordance with embodiments herein. [0039] The oleaginous fluid may be a liquid, such as a natural or synthetic oil. For example, the oleaginous fluid may include one or more of diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids; similar compounds known to one of skill in the art; and mixtures thereof.

[0040] Additives that may be included in the wellbore fluids disclosed herein include, for example, corrosion inhibitors, biocides, pH buffers, mutual solvents, dispersants, thinning agents, rheological additives and cleaning agents. The addition of such agents should be well known to one of ordinary skill in the art of formulating wellbore fluids and muds.

[0041] Methods can be used to prepare the barrier fluids disclosed herein in a manner analogous to those normally used, to prepare oil-based drilling fluids. In one or more embodiments, a desired quantity of oleaginous fluid such as a base oil is heated and sheared prior to adding a styrenic thermoplastic block copolymer to the heated and sheared oleaginous fluid. However, heating of the fluid is not required as the polymers will still result in viscosification without such heat. Dispersion of the polymers in the base oil may be aided by the application of heat. Following the addition of the copolymer, the combined oleaginous fluid and styrenic thermoplastic block copolymer. In one or more embodiments, the heating is performed at a temperature below that of the flashpoint of the oleaginous fluid. Further, in one or more embodiments, the shearing of the combined oleaginous fluid and styrenic thermoplastic block copolymer is at a higher shear rate than the shearing of the oleaginous fluid.

[0042] In some embodiments, the wellbore fluid may be considered an“all-oil” based wellbore fluid. As used herein,“all-oil” refers to the fluid being essentially free of free water. For example, embodiments herein may include a water-absorbing polymer, such as a polyacrylate, to pull residual, entrained, or produced water out of the fluid, binding the water so as to limit the water's ability to interact with the copolymer, precipitated silicas, weighting agents or other additives, minimizing or negating any effect the water may have on the desired properties of the fluid.

[0043] Embodiments of the oil-based barrier fluids disclosed herein may include a base oil, such as an oleaginous fluid and a styrenic copolymer, and optionally included silica (such as a precipitated silica) and weighting agents. The combination of these components may provide for desired viscosity to prevent convection currents when emplaced in a wellbore and held static for a length of time as well as suspension properties (i.e., no settling over a test period).

[0044] Barrier fluids may provide a viscous barrier to ensure separation from a cap and the drilling fluid being pumped downhole when drilling blind. Moreover, such barrier fluids may also be useful in oil or gas well construction operations conducted in extreme temperatures, such as when operating in formations containing permafrost or arctic tundra.

[0045] EXAMPLES

[0046] Various samples of barrier fluids were formulated in different base oils with differing amounts of a styrene-butadiene block copolymer, as shown in Table 1 below. The rheological properties of the fluid samples, including tau zero, were determined using a Fann 35 viscometer.

to (lbf/lOO ft²) | 13.86 _ 35 18 _ 20 25

[0047] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words‘means for’ together with an associated function.

Claims

CLAIMS What is claimed:

1. A capped drilling system, comprising:

a wellbore extending through an earth formation;

a drill string extending through the wellbore, terminating in a drill bit, and defining an annulus between a well of the wellbore and the drill string;

a cap fluid having a density of less than 8.33 ppg in the annulus;

a barrier fluid comprising an oleaginous fluid and styrenic copolymer below the cap fluid; and

a drilling fluid below the barrier fluid.

2. The capped drilling system of claim 1, wherein the styrenic copolymer is a diblock copolymer.

3. The capped drilling system of claim 1, wherein the styrenic copolymer is a triblock copolymer.

4. The capped drilling system of claim 1, wherein comonomers of the styrenic copolymer include styrene and at least one selected from a group of: ethylene, propylene, butylene, butadiene, isoprene, and mixtures thereof.

5. The capped drilling system of claim 1, wherein the cap fluid comprises a gas.

6. The capped drilling system of claim 1, wherein the cap fluid comprises a foamed fluid.

7. The capped drilling system of claim 1, wherein the drilling fluid comprises water.

8. The capped drilling system of claim 1, wherein the drilling fluid comprises an oleaginous fluid.

9. The capped drilling system of claim 1, wherein the barrier fluid further comprises silica particulates.

10. The capped drilling system of claim 1, wherein the barrier fluid further comprises an alkyl diamide.

11. The capped drilling system of claim 9, wherein the alkyl diamide has a formula: Ri-HN- CO-(CH₂)_n-CO-NH-R₂, wherein n is an integer from 1 to 20, Ri is an alkyl groups having from 1 to 20 carbons, and R₂ is hydrogen or an alkyl group having from 1 to 20 carbons.

12. The capped drilling system of claim 1, wherein the oleaginous fluid comprises at least one selected from diesel, a mixture of diesels and paraffin oil, mineral oil, and isomerized olefins.

13. The capped drilling system of claim 1, wherein the barrier fluid acts as an isolation device or floating piston dividing the annulus into a lower region and an upper region, the cap fluid being in the upper region, and the drilling fluid being in the lower region.

14. A method of drilling a wellbore through an earth formation, comprising:

emplacing a barrier fluid into an annulus comprising an oleaginous fluid and a styrenic copolymer;

emplacing a cap fluid having a density of less than 8.33 ppg into an annulus; and emplacing a drilling fluid into the wellbore during drilling;

wherein the cap fluid, the barrier fluid, and the drilling fluid are not returned to the surface during the drilling.

15. The method of claim 13, further comprising:

wherein the cap fluid and the barrier fluid are emplaced upon experiencing losses of a drilling fluid to the earth formation.

16. The method of claim 13, wherein emplacing the barrier fluid divides the annulus into a lower region and an upper region.

17. The method of claim 15, wherein the cap fluid is emplaced in the upper region.

18. The method of claim 13, wherein the drilling fluid is pumped through a drill string that extends into the wellbore.

19. The method of claim 13, wherein the cap fluid comprises a gas.

20. The method of claim 13, wherein the cap fluid comprises a foamed fluid.

21. The method of claim 13, wherein the drilling fluid comprises water.