WO2010054476A1

WO2010054476A1 - Optimization of the liquid injected component for multiphase drilling fluid solutions

Info

Publication number: WO2010054476A1
Application number: PCT/CA2009/001636
Authority: WO
Inventors: Daniel Guy Pomerleau
Original assignee: Daniel Guy Pomerleau
Priority date: 2008-11-13
Filing date: 2009-11-13
Publication date: 2010-05-20

Abstract

The present invention relates to multiphase (MP) drilling fluids and methods of using MP drilling fluids. More specifically, the invention describes multiphase (MP) drilling fluids having a gas component and a liquid component having a gas/liquid ratio (volume % at standard temperature and pressure (STP)), wherein the liquid component is characterized by properties including any one of or a combination of low viscosity, a yield point of less than 20 Pa, a pour point less than -16 °C and flash point greater than 8O°C. The compositions and methods in accordance with the invention can improve surface separation of drill cuttings from drilling fluid as well improving rate of penetration (ROP) during drilling.

Description

OPTIMIZATION OF THE LIQUID INJECTED COMPONENT FOR MULTIPHASE

DRILLING FLUID SOLUTIONS

RELATED APPLICATIONS

[0001] This application claims the benefit of priority to United States provisional application Serial Number 61/114,252 filed November 13, 2008 and is related to a US Provisional application ("the provisional application") filed August 15, 2008 entitled "Multiphase Drilling Systems and Methods" (application serial number unknown) listing Daniel G. Pomerleau, Keith Corb, Stuart Butler, Gregg Jollymore, and Robert Staysko as inventors (attorney docket number WEAT/0890L and/or CPS-5162-PROV-US).

FIELD OF THE INVENTION

[0002] The present invention relates to multiphase (MP) drilling fluids and methods of using MP drilling fluids. More specifically, the invention describes multiphase (MP) drilling fluids having a gas component and a liquid component having a gas/liquid ratio (volume % at standard temperature and pressure (STP)), wherein the liquid component is characterized by properties including any one of or a combination of low viscosity, a yield point of less than 20 Pa, a pour point less than -16 ⁰C and flash point greater than 80⁰C. The compositions and methods in accordance with the invention can improve surface separation of drill cuttings from drilling fluid as well improving rate of penetration (ROP) during drilling.

BACKGROUND OF THE INVENTION

[0003] The drilling of wellbores for the extraction of hydrocarbons continues to evolve with the introduction and development of new technologies.

[0004] By way of background, conventional weighted drilling fluid techniques, air drilling and multi-phase (MP) drilling fluid techniques are briefly discussed.

Weighted Drilling Fluid Drilling

[0005] In conventional weighted drilling fluid drilling, drilling fluids are generally designed to have significant weight to provide a desired hydrostatic pressure in the wellbore. Such fluids are also characterized as having significant viscosity to assist in lifting or removing drill cuttings from the wellbore. Weighted drilling fluids can be generally classified as either oil- or water-based drilling fluids. Both oil- and water-based drilling fluids allow the introduction of various chemicals into the drilling fluid and hence, wellbore in order to manage and/or address various conditions within the wellbore such as gas/water influx, wellbore stability and lost circulation that may occur during drilling.

[0006] The use of conventional weighted drilling fluids can be disadvantaged over other drilling technologies by the initial drilling fluid costs, circulation costs, costs associated with lost circulation, disposal costs and relatively low rates of penetration (ROP).

Air drilling

[0007] Air drilling is a drilling methodology used in certain operations where it may be desired to reduce the hydrostatic pressure in the wellbore. In air drilling, a gas such as air, nitrogen, or natural gas is circulated within the well which allows for a very low equivalent circulating density (ECD) within the wellbore. Air drilling is typically used in areas where the formation is dry and/or the influx of water and/or hydrocarbons is minimal. The main advantages of air drilling are increased rates of penetration (ROP), often in the order of 2-3 times faster than with weighted fluids, the elimination of lost circulation, real-time indication of contact with the pay zone, minimal formation damage and extended bit life. The main disadvantages of air drilling are the inability to handle formation fluids and the ability to contain certain formations such as sloughing shales.

Multiphase Drilling

[0008] Multiphase drilling fluid systems are described in the co-pending provisional application which is incorporated herein by reference. In that application, drilling fluid parameters and their control are discussed as well as various limitations in the design and use of drilling fluids for hydrocarbon discovery and extraction.

[0009] In addition, the provisional application describes the use of drilling fluid systems and methods in which unique drilling fluid compositions are prepared and injected at surface. The compositions include a gas component having an oxygen concentration less than the oxygen concentration sufficient for combustion and a base oil and a liquid volume component which at standard temperature and pressure is less than or equal to 0.025 and greater than or equal to 0.01. [0010] Methods are described in which the above drilling fluids are pumped downhole towards the drill bit such that cuttings from the drill bit are returned to the surface via an annulus defined by an outer surface of a tubular string and an inner surface of a wellbore during drilling operations.

[0011] The compositions and methods described therein are effective in increasing drilling rates (rate of penetration (ROP)).

[0012] The subject application is directed to further improvements in the compositions and methods described in the provisional application.

[0013] By way of further background, drilling systems utilizing either conventional drilling fluids or multiphase (MP) drilling fluid systems require the application of large compressors and mechanical energy input to compress and pump the high gas component fluids downhole at rapid flow rates. These compressors and pumps are generally powered in the field by diesel engines. Depending on the size of the drilling operation, and particularly with conventional drilling fluids, diesel fuel can cost in the range of $20,000 per day to operate these compressors and pumps which represents a significant cost to the operator.

[0014] Due to the high cost of fuel, it is desirable to improve the fuel consumption and the energy consumption efficiency of an MP drilling program.

[0015] Typically, the control parameters for MP energy consumption during drilling operations include but are not limited to gas injection volume/unit time; drillstring design; wellbore design (including casing and open hole sections); drilling fluid injection volume/unit time; and, drilling bit type and jet nozzle size

[0016] Generally, each of these components contributes to the frictional pressure losses which occur when a fluid is circulated in normal drilling operations.

Refrigeration Effect on Fluids During MP Drilling

[0017] Another issue associated with MP drilling is the effect of the compression and expansion of the gases within an MP drilling fluid. That is, during drilling, an MP drilling fluid will experience both a heating effect as the gas component within the drilling fluid is initially compressed at surface and during descent into the wellbore and a refrigeration effect as the gas expands in the wellbore annulus during its return to surface with the liquid component and drill cuttings. Generally, the compression of gases occurs inside the drillstring whereas expansion and cooling occurs in the annulus. As a result of the relative locations of the compression and expansion of gases, and the typical flow rates, at surface the bulk temperature of the drilling fluid and drill cuttings is relatively cool, typically in the range of 10° - 15° C. This relatively low temperature increases the bulk viscosity of the liquid components (primarily oil component viscosity) which subsequently affects the ability to separate drill cuttings from the drill fluid.

[0018] As a result, and in response to the increased viscosity of drilling fluids at the surface, in order to effectively separate drilling fluid from the drill cuttings using common separation technologies such as a shaker screen, the operator will often increase the open area of shaker screens by utilizing a coarser shaker screen. However, the use of a coarser shaker screen does not increase the overall separation of drill cuttings from drilling fluids as a coarser screen will allow smaller cuttings particles through the screen which then decreases the effectiveness and/or increases the load on other downstream separation equipment such as hydrocyclones and centrifuges. Moreover, as the refrigeration effect is particularly pronounced for oil-based drilling fluids in that the viscosities and surface tension of oil-based fluids are more susceptible to temperature changes, this can result in a significant loss of drilling fluid over the shaker. Further still, given typical flow rates, effective heating of the drilling fluids is generally not practical at surface and particularly in winter time.

[0019] The cost of lost drilling fluid as a result of the refrigeration effect can be significant wherein losses in the range of $50,000 per 24 hour period can be realized for a typical well. In addition, decreased effectiveness of separation equipment may result in drilling fluid contamination of drill cuttings approaching 60% by weight of the drill cuttings.

[0020] Accordingly, there continues to be a need for improved methods and systems that minimizes the costs and inefficiencies that result from the refrigeration effect in MP drilling programs.

SUMMARY OF THE INVENTION

[0021] In accordance with the invention, in a first aspect there is provided a multiphase (MP) drilling fluid comprising: a gas component and a liquid component having a gas/liquid ratio (volume % at standard temperature and pressure (STP)), the liquid component characterized as having any one of or a combination of a low viscosity, a yield point of less than 20 Pa, a pour point less than -16 ⁰C and flash point greater than 8O⁰C.

[0022] In further embodiments, the MP drilling fluid comprises a gas/liquid ratio of 85:15 (vol %) and, more preferably a gas/liquid ratio of 97.5:2.5 to 99:1 (vol%) in which the gas/liquid ratio is preferably selected on the basis of strata geopressure. In addition, the viscosity of the liquid component is preferably optimized to promote a transition velocity of the gas component through the liquid component during MP drilling.

[0023] In other more specific embodiments, the yield point of the liquid component is less than 10 Pa and/or the pour point of the liquid component is less than -30 ⁰C.

[0024] In further embodiments, the liquid component density is minimized during recirculation.

[0025] In another embodiment, the liquid component also includes a pour point lowering additive.

[0026] In other embodiments, the liquid component is oil-based and the liquid component includes an emulsifier or water-based and the liquid component includes an alcohol.

[0027] In another aspect, the invention provides a method of using a multi-phase (MP) drilling fluid within a wellbore for drilling comprising the steps of: a. rapidly mixing a gas component and a liquid component to form an MP drilling fluid, the gas component and liquid component having a gas/liquid ratio and wherein the liquid component is characterized as having any one of or a combination of a yield point of less than 20 Pa, a pour point less than -16 ⁰C and flash point greater than 80⁰C prior to mixing. b. pressurizing the MP drilling fluid to the working pressure of the well; c. circulating the MP drilling fluid within the well during drilling; d. at surface, separating the gas component from the liquid component; and, e. at surface separating the liquid component from drill cuttings recovered from the well. [0028] In a further embodiment, steps a)-e) are repeated utilizing recovered liquid component from step e) for re-circulation and wherein the recovered liquid component from step e) is subjected to solids separation of fines to minimize the density of the recovered liquid component prior to re-circulation.

[0029] In yet another embodiment, the viscosity of the liquid component is optimized to promote the transition velocity of the gas component through the liquid component during MP drilling.

[0030] In another embodiment, the plastic viscosity of the liquid component is minimized to promote the transition velocity of the gas component through the liquid component during MP drilling.

[0031] In yet a further embodiment, circulation of the MP drilling fluid maintains a liquid component flow rate of 0.75-6 m³/min and a gas component flow rate of 20-240 m³/min during MP drilling.

[0032] In further embodiments, the method may also include maintaining the density of the liquid component at less than 120% (or 110%) of the density of the original liquid component.

BRIEF DESCRIPTION OF THE FIGURES

[0033] The invention is described with reference to the accompanying figures in which:

Figure 1 is a sketch showing a multi-phase drilling process in accordance with the invention

DETAILED DESCRIPTION Overview

[0034] In accordance with the invention and with reference to the figures, a multiphase (MP) drilling fluid comprising a gas component and a liquid component having a variable gas/liquid ratio (volume % at standard temperature and pressure (STP)) and optional additives is described. The liquid component is characterized as having any one of or a combination of a low viscosity, a yield point of less than 20 Pa, and a low pour point at STP. Within this description, all viscosity values, unless otherwise specified are referenced to 20 ⁰C. [0035] More specifically, the MP drilling fluid comprises a gas/liquid ratio (vol % at STP) of 85:15, and preferably 97.5:2.5 to 99:1. Ideally, the yield point of the liquid component is less than 10 Pa and the pour point of the liquid component is less that -16°C and preferably less than -30 ⁰C. The specific gas and liquids of the MP drilling fluid, the gas/liquid ratio, and any additives utilized will generally be selected by an operator on the basis of geological strata characteristics, geopressure and other considerations.

[0036] In other embodiments, the liquid component density is minimized during recirculation and/or the liquid component viscosity (at STP) is minimized.

[0037] The gas component includes but is not limited to air, nitrogen, oxygen, carbon dioxide or mixtures thereof.

[0038] The liquid component is generally any known drilling fluid including but not limited to invert drilling fluids (eg. 90% oil/10% water), oil based drilling fluids (eg. 100% oil) and water/alcohol based drilling fluids (eg. water/glycerol/glycol emulsions).

[0039] In addition to the base liquid component, additives may be added to the liquid component to provide specific chemical properties to the MP drilling fluid and without significantly affecting the viscosity, pour point or yield point of the liquid component. For example, calcium chloride may be added as a desiccant to promote drying the wellbore if necessary.

Methods

[0040] The invention also describes methods of using multi-phase (MP) drilling fluids within a wellbore for drilling. Generally, the methods of the invention include the following steps: a. rapidly mixing a gas component and a liquid component to form an MP drilling fluid wherein the liquid component is characterized as having a low viscosity, a yield point of less than 20 Pa and/or a low pour point prior to mixing; b. pressurizing the MP drilling fluid to the working pressure of the well; c. circulating the MP drilling fluid within the well during drilling; d. at surface, separating the gas component from the liquid component; e. at surface separating the liquid component from drill cuttings recovered from the well; f. repeating steps a)-f) wherein recovered liquid component from step e) is re-circulated and wherein the density of the recovered liquid component is maintained at less than 120% of the density of the original liquid component.

[0041] As described in greater detail below, importantly, the liquid component is chosen in order that the liquid component density is minimized and/or the liquid component viscosity, pour point and/or yield point (at STP) is minimized within the MP drilling fluid.

Discussion

[0042] It has been determined by field trials by general methods described in the provisional application that in order to optimize overall energy efficiency, it is desirable to minimize the density of the liquid component of the MP drilling fluid injected at surface in order to provide operational advantages to MP drilling such as reducing hydrostatic backpressure on the injected drilling fluid during MP drilling. As described in the provisional application, during circulation of a MP drilling fluid, the behaviour of the MP drilling fluid will vary depending where in the system the MP drilling fluid is.

[0043] That is, as shown in Figure 1 , there are 5 general sections A-E through which the MP drilling fluid passes during drilling. Within each section, the MP drilling fluid will have different properties which cause different effects. For the purposes of this description, the control of drilling fluids properties is made to affect the behaviour of the drilling fluids in all 5 sections.

[0044] In sections A and B the properties of the injected liquid component fluid will have the greatest effect on the frictional pressure losses and may be approximated using equations of the following form;

ΔP = 2H pV²ZD f= c / Re^b c = (log n + 2.5)/50 b = (1.4 - log n)/7 where f is Fanning friction factor, L is the length of the section, P is frictional pressure loss, p is fluid density,V is fluid velocity, D is the inside diameter of pipe, Re is the Reynolds Number and n is slope of the line for the logarithmic values relating to fluid viscosity and shear rate.

[0045] In Sections B, C & E, the MP drilling fluid is dominated by the liquid component (typically beneath 150m of depth). In Section C, an MP drilling fluid is affected by a "bubble flow" state that affects the properties of the MP drilling fluid. More specifically, bubble flow, is described as a state in which bubbles of the gas component are dispersed within the MP drilling fluid. Generally, frictional pressure losses associated with pumping the MP drilling fluid during this stage are dominated by the liquid/gas injection ratios, viscosity of the injected liquid, and density of the injected liquid, these factors all directly affect the Equivalent Circulating Density (ECD)), The frictional pressure losses for section C may be determined with an equation of the following type:

ΔP = 2fL pV²/ φ Φ = .8165 (Do -Di) where Do is the hole diameter and Di is the outside diameter of pipe in the hole.

[0046] In section E losses as the MP fluid transits the bit nozzles and the resistance arising from the bubble effect. These effects cause an increase in gas injection pressure required and increases energy required to circulate drilling fluids in the system. Calculation of this pressure loss may only be estimated with the following equation:

ΔP = 2fL pV²/D

[0047] Generally, the ECD is determined by the density of the circulated fluid, which is controlled by liquid injection volume, gas injected volume, and frictional pressure losses; caused by fluid viscosity, occurring in the annulus of the circulating system. Currently no accurate model exists to predict frictional pressure losses in the circulating system for MP drilling fluid systems severely restricting the engineering that can be applied to a MP drilling format. The frictional pressure loss equations that are normally utilized for conventional drilling fluid systems are as follows:

(Pp / U (U = /p Vp² p / 25.81 ( D₀ - D,) (Annulus) (Pp / U) (U) = f_p Vp² p / 25.81 D (Pipes) [0048] By reducing the density of the injected liquid fluid component at surface, energy requirements at surface will be reduced as the surface pumps and compressors will require less energy to overcome fluid resistance. Reductions of 2% in liquid component density have resulted in a 5% reduction in fuel consumption for a MP drilling program. Reductions in yield point (YP) (discussed below) of a drilling fluid to below 10 Pa have reduced fuel consumption by 10%.

[0049] In addition, maintaining a liquid component density not higher than 20% greater (preferably not higher than 10%) than the prepared fluids initial density during drilling and re-circulation will also contribute to a reduction in energy input to the system. In other words, as re-circulation of drilling fluid occurs over the course of a drilling program, the density of the liquid component will naturally increase as the drilling fluid becomes progressively more saturated with drill cuttings and specifically drill cutting fines. The use of solids separation equipment at surface are generally able to remove all solids using screens, centrifuges and hydrocyclones as known to those skilled in the art, however it is also known that solids separation equipment is not able to remove "fines" from the drilling fluid. As a result, the density of the drilling fluid will progressively increase over time as more and more fines become suspended within the liquid component. This is also compounded by the refrigeration effect.

[0050] Furthermore, as the density and concentration of solids in the liquid component increases, the increasing concentration of solids will detrimentally affect the rheological properties of the injected liquid component. Specifically, increasing solids concentration will increase viscosity which can significantly impair the transition velocity of the gas component as it transits the liquid dominated column in the annulus of the excavation.

[0051] This impairment causes a backpressure effect on the circulating system requiring an increase in gas injection pressure to overcome this problem.

[0052] Although no model has been developed to accurately measure the effect of fluid viscosity on gas bubble transition, it is theorized that the model may be similar to that used to measure the slip velocities of drilled cutting in a conventional drilling fluid wherein:

V_s = .01294 ( μ_e / (Dp p ) (Cuttings Slip Velocity Equation) B_h, = .01294 ( μ_e / (D_p p ) + Injection Velocity Btv = Bubble transition velocity [0053] Determining bubble size or D_p in the annulus is the single most difficult challenge with respect to this question.

[0054] Furthermore, the same restrictive effect exists inside the drillpipes, collars, and bit jet nozzles in the drillstring as the gas attempts to pass through the liquid as it transits to the bottom of the excavation. Again, no equation models exist to measure this at the present time. However, the effect on the rheology of the fluid by drilled solids is typically seen as an increase in viscosity. This increase in viscosity affects the values of n; fluid velocity profile or boundary layer form, K; fluid consistency index, μ_e ; effective viscosity of the fluid, Re; Reynolds number, f_Pι Friction factor, and thereby the V_s and (P_p / U) (U) where: n = log (T₁ / T₂) / log (Y₁ / γ₂) K = τ_x/ γ_x" μ_e = 100 K Y "-'

Re = 928 Vp D p / μ_e or Re = 928 V_p ( D₀ - D,) p / μ_e

T = Shear stress Y = Shear Rate

[0055] As shown in Figure 1 , MP drilling is described. A gas component 12 and liquid drilling fluid component 14 are rapidly mixed 16 at surface and compressed 18 to the working pressure of a well 20. Thus, if 98 m³ of gas is mixed with 2 m³ of liquid drilling fluid and compressed to 3000 psi, the approximate total volume of the MP drilling fluid would be in the range of 4.5 m³ such that the gas component (approximately 2.5 m³) constitutes approximately 60% of the total volume of the injected multiphase mixture and the liquid component (2.0 m³) constitutes approximately 40% of the total volume of the injected mixture. The MP fluid is injected into the well at flow rates typically used in a drilling operation, namely 1-5 m³/min.

[0056] Near the surface A, where hydrostatic pressures are minimal, the gas and liquid components will generally be an emulsion of liquid dispersed in a gas. As hydrostatic pressures increase as the mixture descends the well, the gas volume will be reduced such that the gas component volume relative to the liquid component volume becomes less, which depending on the pressures involved cause an inversion such that the gas phase is dispersed with the liquid phase (Section B). [0057] At the drill bit, the mixture is rapidly ejected through the drill bit. The force of ejection, high shear rates and resulting turbulence, in combination with the pumping rate, aid in fracturing the drilled strata as well as lifting and carrying drill cuttings with the now rising drilling fluid.

[0058] As the MP drilling fluid rises through the well (Section C), hydrostatic pressure will reduce thus increasing the volume of the gas component relative to the liquid component. The expanding gas will cause the drilling fluid temperature to cool and the μ_eto increase.

[0059] At surface, the now combined mixture of gas, drilling fluid and drill cuttings must be effectively separated. Specifically, the gas must be separated from the liquid component to enable the liquid component to be transferred to the solids separation systems 20 including but not limited to screening machines centrifuges and hydrocyclones where the drill cuttings are separated from the liquid drilling fluid.

[0060] As a result of the high level of saturation of the liquid component with gas, the release of pressure to enable separation must be controlled so as maintain safe operation at the well head.

[0061] As separation is occurring in a cooling drilling fluid (due to gas expansion), the effects of liquid component viscosity become important in the separation of liquid and gas components.

[0062] Furthermore and unexpectedly, it has been determined that reducing liquid component viscosity and density (and maintaining a low density during re-circulation) in a MP mixture has provided superior hole cleaning capabilities compared to a conventional (i.e. non MP drilling fluid) drilling fluid while further providing the advantages of a MP fluid on ROP. The MP system has been able to drill at rates of 250 m/hr (measured instantaneous drilling rate) and successfully clean the wellbore at this rate. In comparison conventional drilling operation systems and fluids will typically show maximum ROPs of an order of magnitude less.

Viscosity and Yield Point Optimization

[0063] As noted, in accordance with the invention, it is desired to optimize the overall fluid viscosity of the liquid component at surface to ensure ease of transit of the injected gas through the MP drilling fluid column and to minimize the refrigeration effect on cuttings separation. In conventional drilling, the drilling fluid viscosity and fluid injection rate are balanced to ensure that that cuttings transport out of the wellbore is optimized. Conventionally, the drilling fluid viscosity parameters typically monitored for this optimization are the Bingham fluid values of Plastic Viscosity (PV), Yield Point (YP), and, Power Law values of fluid velocity flow profile or boundary layer as indicated from the "n" and the fluid consistency index as indicated by the "K" value.

[0064] Typically, in the past, it has been known that for any fluid injection rate where the fluid flow in the annulus is generally laminar or non-turbulent, the higher the viscosity, the better, the hole cleaning.

[0065] In MP fluid systems and in accordance with the invention, the drilling fluid parameters that are optimal for conventional systems impair the ability of the injected gas to transit the fluid in the annulus. In particular, and as noted above and in the provisional application, a high viscosity μ_e in the liquid component impairs the ability of the gas component to transit during the "bubble flow" phase in the annulus.

[0066] In other words, it has been understood that the ability to remove drill cuttings from the wellbore requires sufficient viscosity μ_e of drilling fluid in the annulus to carry drill cuttings through the annulus to surface. In accordance with the invention, multiphase drilling fluids having lower inherent liquid viscosity in the liquid phase are utilized to effectively carry drill cuttings to surface with the lower viscosity liquid phase drilling fluid being balanced against higher drilling fluid flow rates and increased gas content. More specifically, the liquid phase viscosity is characterized as having a Yield Point less than 20 Pa and preferably less than 10 Pa. This low YP will ensure that gas transition is as efficient as possible. Moreover, the relationship between YP and μ_e is defined below.

Plastic Viscosity (PV) = T₆₀₀ - T₃₀₀ Yield Point (YP) = T₃₀₀ - PV

[0067] In MP drilling fluids, it has unexpectedly been found that a high yield point drilling fluid is not required for effective ROP or for carrying drill cuttings. In addition, it has been determined that the use of low YP drilling fluids reduces drill cutting separation problems that may result from the refrigeration effect. Pour Point

[0068] Pour point is the temperature at which a substance will begin to flow. Generally, in conventional drilling fluids, the use of low pour point oils has been minimized as low pour point oils do not effectively contribute to the viscosity of the drilling fluid. More specifically, low pour point oils will typically have shorter hydrocarbon chain lengths and thus, a lower viscosity at any given temperature as compared to oils having higher pour points. Unexpectedly, it has been found that low pour oils in MP drilling fluids remain effective for carrying drill cuttings while both minimizing the refrigeration effect and enabling faster ROPs.

[0069] Accordingly, oil based fluids should be formulated with low pour point oils to reduce the viscosity of the oil or oil based drilling fluids when they arrive at surface. For example, typically using oils used in MP drilling are C12 - C14 Internal Olefins and Linear Alpha Olefins and distillated diesel fractions. Typical pour points are in the range of -20° to -50⁰C.

[0070] Examples of low pour point oils are Amodrill 1400 synthetic olefin (C14), Amodrill 1410 synthetic olefin, and Amodril 1500 (C12/C12) (BP, Naperville, Illinois). Other examples include Puredrill HT-30 and HT-40, Krystol 20 (Petro-Canada, Calgary, Alberta), and Drillsol Plus, (Enerchem International Inc., Nisku, Alberta). [0071] In addition, the addition of pour point reducing chemicals may be utilized for those oils in which pour point depression may be desirable. Examples of pour point reducing chemicals include CP 3840, CP 3810 and CP 3830D (Total France, Puteaux, France).

Flash Point

[0072] Another important consideration is that while low pour point oils having lower surface tension on drill cuttings improve the separation efficiency, many such oils also have a lower flash point. As a result, it is important that the operator take appropriate steps as may be required to mitigate the explosion risk that may be presented with lower flash point oils. For example, oils such as Exxon Tetramer K with a pour point of -100 ⁰C and a flash point of 58 ⁰C may not be suitable.

[0073] Importantly, there are many oils having pour point of -20 ⁰C to -60 ⁰C and flash points of > 80 °C. Such oils may be particularly beneficial for use in winter conditions when the ambient air temperature can be in the range of -40 ⁰C. Density

[0074] As noted, it is desired to maintain the density of the liquid component to less than 120% of the original liquid component density.

[0075] Representative examples are discussed.

[0076] In the case of an invert emulsion oil based drilling fluid system with a 90/10 oil/water ratio where the primary oil phase has a density of 760 kg/m³, the prepared fluid density with a water phase containing 30% by weight CaCI₂ would be on the order of 830 kg/m³.

[0077] As a result, in accordance with the invention, it is important to control the combined fluid density at or optimally below 830 x 1.2 = 996 kg/m³ during drilling.

[0078] In the case where the drilling fluid is an oil drilling fluid with an initial density of 760 kg/m³ then an operating density of lower then 760 x 1.2 = 912 kg/m³ would be optimal.

[0079] For water based fluids this same rule is applied to fresh water, salt brines, combinations thereof and direct emulsions where there is an internal phase in the water including but not limited to oils, glycerol, glycol, et al. Further the rule extends to invert emulsions where the external phase comprised a glycol or glycerol based fluid. Typical density numbers would be in the range from 1000 kg/m³ for pure water systems with higher values if salts are dissolved in water and lower values if oils, alcohols, or other additives are dispersed into the fluid.

High Shearing at the Bit Face

[0080] In accordance with the methods of the invention, as a result of the relatively high circulation rates and low viscosity liquids, MP drilling enables the operator to maintain very high shearing levels at the bit face which allows for significantly higher ROPs.

MP Drilling Fluid Protocol Example

[0081] The following is an example of a drilling protocol that may be followed utilizing an MP drilling fluid. In this example, a low pour point oil such as Pure Drill HT30N base oil (pour point -36°C; density 820 kg/m³) is utilized. a. Fill mud tanks with HT30N base oil for drillout. b. Prepare HT30N mud on location (typically about ~ 60m³) to be used for trip slugs and for viscosifying the base oil at casing point. c. Prepare and utilize MP drilling fluid for drilling. The MP drilling fluid will be prepared at 85/15 to 99/1 volume % gas/liquid. d. At drillout, have 50/70 mesh shaker screens on shaker and adjust to as fine a screen as possible. e. Run Centrifuges consistently.

[0082] The circulating rates that would typically be employed for MP drilling are as follows:

Table 1 -Circulating Rates for MP Drilling

Other Considerations in Optimizing MP Drilling Fluid Performance and Minimizing the Refrigeration Effect

[0083] Additional considerations in optimizing MP drilling fluid performance include the performance of surface equipment including gas/fluid separators, shaker/screening machines, centrifuges, and hydrocyclones. Each of these machines apply a shearing force to the MP fluid to separate solids and entrained gas from the fluid as it is processed through the equipment. As a result, the lower the shear stress for the shear rate applied by this equipment the more effective the separation. The gas/fluid separation effect is also important as high viscosity fluids used with past MP drilling fluid systems resulted in poor separation and large amounts of the liquid components were lost through the gas venting equipment on location.

[0084] As a result, gas/fluid separation is optimized by a low viscosity liquid component. In other words, the greater the difference in viscosity between a gas and fluid will adversely affect the ability to separate the gas and the fluid.

[0085] As noted above, the temperature of the MF drilling fluid as it is arriving at surface is typically in the range of 10-15° C as compared to temperatures in the range of 50° C or higher downhole. As the gas rapidly expands as it rises up through the wellbore annulus, the MP drilling fluid will be cooling which has the effect of increasing liquid component viscosity. As a result, the cooling effect will generally decrease the performance of separation equipment and solid control equipment at the surface.

[0086] Accordingly, in formulating a MP drilling program utilizing any of an oil-based drilling fluid, alcohol-based drilling fluid or water-based drilling fluid requires specific actions.

[0087] Oil based drilling fluids should be formulated with minimal use of organophilic clay viscosifiers while at the same time treating the fluid with some emulsifiers such as fatty acids, DETA, lecithins, CaDoBS, ionic and non-ionic emulsifiers of various hydrophilic lipophilic balance (HLB) and water ionizing materials including but not limited to CaO "Quick Lime" Hydrophilic Polymers coarse/granular grade and CaCI₂ .

[0088] Furthermore, when using water-based MP drilling fluids, viscosity is also affected by the cooling effect. In this case, the refrigeration effect may be tempered with alcohols, glycols etc.

Separation Systems

[0089] As noted above, the cooling effect can cause significant increases in fluid viscosity resulting in separation issues at surface. More specifically, poor gas/liquid separation can result in drilling fluid venting out gas relief lines, blinding off the shakers resulting significant losses of drilling fluid.

[0090] When using a pure un-viscosified oil to drill, it is preferable to add small amounts of emulsifier/oil wetting agent and lime; specifically calcium oxide. The emulsifier and/or oil wetting agent can emulsify/oil wet any water wet strata that is excavated and the calcium oxide can ionize invading water. If these steps do not occur, entry of water can cause destabilization of the wellbore and water wet cuttings will stick to the shaker screens causing increased losses of drilling fluid.

Results

[0091] Table 2 shows a representative comparison between different wells drilled using MP drilling fluids of different pour points and gas/liquid rations. As shown, Well 1 using a higher pour point oil in a 90/10 gas/liquid mixture resulted in significant surface losses. As shown for Wells 2, 3 and 4 in which a lower pour point oil was utilized, there was substantially lower surface losses.

Table 2-Surface Losses by Well Size and Base Oil Pour Point

[0092] That is, during testing, it was found that under fair weather drilling conditions (15 - 20 ⁰C ambient temperature) that adjusting the pour point of the liquid component from -10 ⁰C to -35 ⁰C resulted in a wt% reduction of oil retained on cuttings from 27 wt% to 7wt% when standard 50 mesh screens were used at surface. In the case where 84 mesh screens were utilized, there was a wt% reduction from 42 wt% to 15wt%.

Discussion of the Effect of Rheological Characteristics on the Performance of Multiphase Drilling Fluids.

[0093] The rheological character of a fluid is exhibited by the fluids shear stress response to shear rate or flow rate. Several different mathematical models exist for explaining these characteristics, with the most widely accepted models being the Bingham and Power-Law.

[0094] The Bingham model constants, (PV) Plastic Viscosity and (YP) Yield Point, are the most widely accepted for evaluating drilling fluid flow.

[0095] Power-law fluids can be subdivided into two different types of fluids namely pseudoplastic or shear-thinning fluids and Newtonian fluids based on the value of their flow behavior index:

[0096] Pseudoplastic, or shear-thinning fluids have a lower apparent viscosity at higher shear rates, and are usually solutions of large, polymeric molecules in a solvent with smaller molecules. It is generally supposed that the large molecular chains tumble at random and affect large volumes of fluid under low shear, but that they gradually align themselves in the direction of increasing shear and produce less resistance.

[0097] A Newtonian fluid is a power-law fluid with a behavior index of 1 , where the shear stress is directly proportional to the shear rate.

[0098] As discussed earlier, it is recommended that the liquid component in a multiphase fluid should have its viscosity engineered to provide the least amount of resistance to the passage of gas through the liquid during circulation.

[0099] Achieving this objective by reducing the yield point to less than 20 Pa is one objective in accordance with the invention.

[00100] However, it is also advantageous to make the fluid as shear thinning as possible. This shear thinning effect can be achieved by reducing the plastic viscosity value relative to the yield point value thereby increasing the non-Newtonian, Pseudoplastic or Thixotropic character of the fluid.

[00101] In this regard, the best way to determine the non-Newtonian character of a fluid is to calculate the dimensionless value "n" the flow behavior index for the fluid. This value also provides an idea as to the shape of the boundary layer as the fluid passes against a rigid body. As is known, the "n" indicates the degree of non-Newtonian behavior that a fluid exhibits over a defined shear rate range. Newtonian fluids tend to exhibit a calculated value of close to or equal to one and as the value decreases from one the fluid becomes shear thinning or Pseudoplastic. n = log (T / T') / log (Y / Y') and K = τ / γ "

[00102] Using an example of two fluids with equivalent yield points of 5 Pa and equivalent specific gravity, it can be seen that fluids having the same YP can have substantially different viscosities as plastic viscosity varies. In this comparison, fluid 1 had a plastic viscosity of 25 and fluid 2 had a plastic viscosity of 3. Samples were taken from 2 wells drilled in Alberta (Table 3).

Table 3-Representative Drilling Fluid Parameters of Fluids with Equivalent Yield Points

[00103] As indicated, the significantly greater K value or flow consistency index of fluid 2 indicates a better lifting viscosity characteristic. The lower Marsh Funnel viscosity indicates superior shear thinning properties when subjected to the modest shearing energy effects of a Marsh funnel. This characteristic also allows for superior transition of the gas through the liquid component reducing energy consumption.

[00104] Although the present invention has been described and illustrated with respect to preferred embodiments and preferred uses thereof, it is not to be so limited since modifications and changes can be made therein which are within the full, intended scope of the invention as understood by those skilled in the art.

Claims

1) A multiphase (MP) drilling fluid comprising: a gas component and a liquid component having a gas/liquid ratio (volume % at standard temperature and pressure (STP)), the liquid component characterized as having any one of or a combination of a yield point of less than 20 Pa, a pour point less than -16 ⁰C and flash point greater than 80⁰C.

2) The multiphase (MP) drilling fluid as in claim 1 wherein the MP drilling fluid comprises a gas/liquid ratio of 85:15 (vol %).

3) The multiphase (MP) drilling fluid as in claim 2 wherein the MP drilling fluid comprises a gas/liquid ratio of 97.5:2.5 to 99:1 (vol%).

4) The multiphase (MP) drilling fluid as in any one of claims 1-3 wherein the gas/liquid ratio is selected on the basis of strata geopressure.

5) The multiphase (MP) drilling fluid as in any one of claims 1-4 wherein the viscosity of the liquid component is optimized to promote a transition velocity of the gas component through the liquid component during MP drilling.

6) The MP drilling fluid as in any one of claims 1-5 wherein the yield point of the liquid component is less than 10 Pa.

7) The MP drilling fluid as in any one of claims 1-6 wherein the pour point of the liquid component is less than -30 ⁰C.

8) The MP drilling fluid as in any one of claims 1-7 wherein the liquid component density is minimized during re-circulation.

9) The MP drilling fluid as in any one of claims 1-8 wherein the liquid component viscosity (at STP) is minimized.

10) The MP drilling fluid as in any one of claims 1-7 further comprising a pour point lowering additive.

11 ) The MP drilling fluid as in any one of claims 1-10 wherein the liquid component is oil- based and the liquid component includes an emulsifier.

12) The MP drilling fluid as in any one of claims 1-10 wherein the liquid component is water-based and the liquid component includes an alcohol. 13) A method of using a multi-phase (MP) drilling fluid within a wellbore for drilling comprising the steps of: a) rapidly mixing a gas component and a liquid component to form an MP drilling fluid, the gas component and liquid component having a gas/liquid ratio and wherein the liquid component is characterized as having any one of or a combination of a yield point of less than 20 Pa, a pour point less than -16 ⁰C and flash point greater than 8O⁰C prior to mixing. b) pressurizing the MP drilling fluid to the working pressure of the well; c) circulating the MP drilling fluid within the well during drilling; d) at surface, separating the gas component from the liquid component; and, e) at surface separating the liquid component from drill cuttings recovered from the well.

14) The method as in claim 13 further comprising the step of: repeating steps a)-e) utilizing recovered liquid component from step e) for re-circulation and wherein the recovered liquid component from step e) is subjected to solids separation of fines to minimize the density of the recovered liquid component prior to re-circulation.

15) The method as in any one of claims 13-14 wherein the viscosity of the liquid component is optimized to promote the transition velocity of the gas component through the liquid component during MP drilling.

16) The method as in any one of claims 13-15 wherein the plastic viscosity of the liquid component is minimized to promote the transition velocity of the gas component through the liquid component during MP drilling.

17) The method as in any one of claims 13-16 wherein circulation of the MP drilling fluid maintains a liquid component flow rate of 0.75-6 m³/min and a gas component flow rate of 20-240 m³/min during MP drilling.

18) The method as in any one of claims 13-17 wherein the gas/liquid ratio is 85:15.

19) The method as in claim 18 wherein the gas/liquid ration is 97.5:2.5 to 99:1 (volume % at standard temperature and pressure).

20) The method as in any one of claims 13-19 wherein the yield point is less than 10 Pa.

21 ) The method as in any one of claims 13-20 wherein the pour point is less than -30 ⁰C. 22) The method as in any one of claims 14-21 wherein the density is maintained at less than 120% of the density of the original liquid component.

23) The method as in any one of claims 14-21 wherein the density is maintained at less than 110% of the density of the original liquid component.

24) The method as in any one of claims 13-23 wherein the liquid component viscosity (at STP) is minimized prior to step a).