CA3015848A1

CA3015848A1 - Compositions and methods for shale stabilization

Info

Publication number: CA3015848A1
Application number: CA3015848A
Authority: CA
Inventors: Devon Erick HANSON; Kuangbiao Ma; Stuart Dubberley; Matthew DEWIT
Original assignee: Secure Energy Drilling Services Inc
Current assignee: Secure Energy Drilling Services Inc
Priority date: 2016-03-02
Filing date: 2017-03-02
Publication date: 2017-09-08
Also published as: WO2017147712A1

Abstract

Drilling fluid compositions comprising a formate salt and a silicate salt, as well as methods and uses thereof in drill operations, are provided. The drilling fluid compositions may comprise, for example, sodium silicate and potassium formate, and may be used as a shale stabilizing agent, a fluid loss reduction agent, a drilled formation stabilizer, and/or a coal stabilizer. Processes for the preparation of such drilling fluid compositions are also provided.

Description

2 PCT/CA2017/050287 COMPOSITIONS AND METHODS FOR SHALE STABILIZATION
FIELD OF INVENTION
The present invention relates generally to drilling operations and fluids therefor. More specifically, the present invention relates to compositions and methods for shale stabilization and/or fluid loss reduction in drilling operations.
BACKGROUND
Natural resource exploration and recovery often requires the drilling of subterranean formations.
Drills are used to bore holes into the earth, creating wellbores for exploring, accessing, and/or recovering natural resources in subterranean formations. Drilling operations often employ drilling fluids, also referred to as drilling muds, to facilitate drilling by cooling the drill bit, and by carrying drill cuttings out of the wellbore during circulation of the drilling fluid in the wellbore.
A wide variety of drilling fluid compositions and drilling fluid additives providing advantageous properties have been developed in the field. By way of example, agents for providing increased fluid viscosity and density have been described which facilitate carry out of drill cuttings from the wellbore. Agents developed for reducing wear and tear on drill heads during drilling have also been described.
Despite the benefits provided by modern drilling fluids, their use is often restricted by cost considerations. Aqueous formate brine-based drilling fluids, for example, represent drilling fluids which can provide several benefits to drilling operations. Their application is, however, limited due to difficulties associated with fluid loss. Indeed, fluid loss of such drilling fluids from fractured and/or highly porous formations is challenging to control, and may result in loss of large volumes of drilling fluid to the subterranean formation, greatly reducing drilling fluid recovery. Such fluid loss may add significant cost to a drilling operation due to the expensive nature of, for example, potassium formate brines. Current practice is to avoid the use of potassium formate when high loss zones are anticipated, as the operation may become prohibitively expensive compared to other fluid options.
In addition to fluid losses associated with the drilling of subterranean formations, shale instability can also impose complications when subterranean formations and their surroundings comprise shale. In aqueous-based drilling fluids, for example, water may interact with shale and clay components therein, causing swelling and/or disaggregation. These effects may result in wellbore instability and/or creation of fractures allowing for fluid loss, potentially adding significant expense to such drilling operations.
An alternative, additional, and/or improved drilling fluid and/or method of use thereof is desirable.
SUMMARY OF INVENTION
In one embodiment, the present invention provides for an aqueous drilling fluid comprising:
a formate salt; and a silicate salt.
In another embodiment of an aqueous drilling fluid as outlined above, the formate salt is potassium formate, cesium formate, or sodium formate.
In another embodiment of an aqueous drilling fluid as outlined above, the silicate salt is sodium silicate.
In another embodiment of an aqueous drilling fluid as outlined above, the silicate salt is sodium silicate having about a 0.5:1 to about a 4:1 wt:wt ratio of Si02:Na20, such as a 2:1 Si02:Na20 ratio, or a 1.8:1 Si02:Na20 ratio.
In another embodiment of an aqueous drilling fluid as outlined above, the aqueous drilling fluid is a potassium formate brine-based drilling fluid, a cesium formate brine-based drilling fluid, or a sodium formate brine-based drilling fluid.

In another embodiment of an aqueous drilling fluid as outlined above, a fluid density of the potassium formate brine, the cesium formate brine, or the sodium formate brine is about 1000kg/m3 (1.00 SG) to about 1500kg/m3 (1.50SG).
In another embodiment of an aqueous drilling fluid as outlined above, a fluid density of the potassium formate brine, the cesium formate brine, or the sodium formate brine is about 1200kg/m3 (1.2 SG) to about 1500kg/m3 (1.50SG).
In another embodiment of an aqueous drilling fluid as outlined above, a fluid density of the potassium formate brine, the cesium formate brine, or the sodium formate brine is about 1000 kg/m3 to about 1400 kg/m3.
In another embodiment of an aqueous drilling fluid as outlined above, the aqueous drilling fluid is a potassium formate brine-based drilling fluid having a fluid density of about 1400 kg/m3 and the silicate salt is a sodium silicate.
In another embodiment of an aqueous drilling fluid as outlined above, the silicate salt component is a silicate salt solution, and the silicate salt solution has a concentration in the aqueous drilling fluid of about 0.1%-30% v/v.
In another embodiment of an aqueous drilling fluid as outlined above, the silicate salt solution has a concentration in the aqueous drilling fluid of about 1%-15% v/v.
In another embodiment of an aqueous drilling fluid as outlined above, the silicate salt solution has a concentration in the aqueous drilling fluid of about 1%-10% v/v.
In another embodiment of an aqueous drilling fluid as outlined above, the silicate salt solution has a concentration in the aqueous drilling fluid of about 8%-10% v/v.
In another embodiment of an aqueous drilling fluid as outlined above, the aqueous drilling fluid comprises from about a 99.9:0.1 v/v ratio of formate brine: sodium silicate solution to about 70:30 v/v ratio of formate brine: sodium silicate solution.
In another embodiment of an aqueous drilling fluid as outlined above, the aqueous drilling fluid

3 comprises about a 85:15, 92:8, or a 90:10, v/v ratio of 1250 kg/m3 ¨ 1400 kg/m3 potassium formate brine: sodium silicate solution.
In another embodiment of an aqueous drilling fluid as outlined above, the aqueous drilling fluid comprises about a 90:10 v/v ratio of formate brine: sodium silicate solution.
In another embodiment of an aqueous drilling fluid as outlined above, the sodium silicate solution is about 0.1-50 w/v sodium silicate, such as about 44 wt% sodium silicate in water.
In another embodiment of an aqueous drilling fluid as outlined above, the drilling fluid is a clear brine system substantially free of solids.
In another embodiment of an aqueous drilling fluid as outlined above, wherein the drilling fluid is a drilling mud and further comprises a fluid loss polymer and/or a viscosity control polymer.
In yet another embodiment, the present invention provides for a process for preparing an aqueous drilling fluid as defined above, the process comprising:
providing an aqueous potassium formate brine solution, cesium formate brine solution, or sodium formate brine solution, and mixing a concentrated sodium silicate solution with the potassium formate brine solution, cesium formate brine solution, or sodium formate brine solution;
or providing a water-diluted sodium silicate solution, and mixing a concentrated potassium formate brine or a potassium formate salt, a concentrated cesium formate brine or a cesium formate salt, or a concentrated sodium formate brine or a sodium formate salt, with the sodium silicate solution.
In yet another embodiment, the present invention provides for a method for drilling a subterranean formation comprising shale, limestone, dolomite, sandstone, evaporite, mud stone or coal, the method comprising:

4 drilling into the subterranean formation using a drill, thereby forming a wellbore;
and circulating an aqueous drilling fluid as outlined above in the wellbore simultaneously or sequentially with drilling, thereby reducing damage to shale, limestone, dolomite, sandstone, evaporite, mud stone or coal surrounding the wellbore caused by swelling or disaggregation.
In yet another embodiment, the present invention provides for a method for drilling a subterranean formation, the method comprising:
drilling into the subterranean formation using a drill, thereby forming a wellbore;
circulating an aqueous drilling fluid as outlined above in the wellbore simultaneously or sequentially with drilling, thereby sealing microfractures in the wellbore and/or the subterranean formation; and recovering at least a portion of the aqueous drilling fluid.
In yet another embodiment, the present invention provides for a use of the aqueous drilling fluid as outline above as a shale inhibitor, a fluid loss reduction agent, a drilled formation stabilizer, and/or a coal stabilizer.
BRIEF DESCRIPTION OF DRAWINGS
FIGURE 1 shows an example of cost per meter drilled of wells drilled using potassium formate-containing drilling fluids, wherein a high-seepage loss well (far left) is compared with minimal seepage loss wells;
FIGURE 2 shows a photograph of a representative sample of a 92:8 v/v mixture of 1250 kg/m3 potassium formate brine: sodium silicate solution. As shown, the fluid remained clear and colourless, with no signs of precipitate formation, indicating excellent compatibility;
FIGURE 3 shows the shale recovery percent obtained for Pierre Shale using a variety of potassium formate and silicate-containing fluids;

FIGURE 4 is a photograph of samples of 1400 kg/m3 Potassium Formate + 10%
Sodium Silicate ¨ D: Initial Solids Flocculation;
FIGURE 5 is a photograph of samples of 1400 kg/m3 Potassium Formate + 10%
Sodium Silicate ¨ D: Solids Flocculation after 5 Minutes; and FIGURE 6 shows a graph of the Sodium Silicate ¨ D (also referred to herein as K-ForMax Seal) concentration relative to drill depth for the field trial.
DETAILED DESCRIPTION
Described herein are aqueous drilling fluids, methods and uses thereof, as well as processes for the preparation thereof. It will be appreciated that embodiments and examples are provided herein for illustrative purposes intended for those skilled in the art, and are not meant to be limiting in any way.
In an embodiment, there is provided herein an aqueous drilling fluid comprising:
a formate salt; and a silicate salt.
By way of example, a formate salt may include an alkali metal salt of formic acid, such as potassium formate, cesium formate, or sodium formate. By way of further example, a silicate salt may include an alkali metal salt of silicate, such as sodium silicate.
As described in further detail herein, such aqueous drilling fluids may demonstrate shale stabilization properties, coal stabilization properties, enhanced shale recoveries, and/or fluid loss reduction properties in drilling operations.
It will be understood by the person of skill in the art that more than one form of sodium silicate may be obtained. In industrial applications, sodium silicate is often characterized by its 5i02:Na20 weight ratio, which may also be related to alkalinity. In certain embodiments, an alkaline or neutral grade may be used. In certain other embodiments, an alkaline grade may be used. In an embodiment, a sodium silicate having about a 0.5:1 to about a 4:1 wt:wt ratio of Si02:Na20 may be used. In another embodiment, a 2:1 Si02:Na20 ratio grade may be used. In yet another embodiment, a 1.8:1 Si02:Na20 ratio grade may be used.
In certain embodiments, the aqueous drilling fluids described herein may be potassium formate brine-based drilling fluids, cesium formate brine-based drilling fluids, or sodium formate brine-based drilling fluids. In other embodiments, the drilling fluids may be based on a traditional mud based drilling fluid.
In another embodiment, the aqueous drilling fluids described herein may be characterized by a fluid density of the formate brine which is about 1250 kg/m3to about 1400 kg/m3, or less.
In another embodiment, the aqueous drilling fluids described herein may be characterized by a fluid density of the formate brine which is about 1000 kg/m' (1.00 SG) to about 1500 kg/m' (1.50 SG).
It will be understood that aqueous drilling fluids as described herein may have a variety of different formate salt concentrations, silicate salt concentrations, and/or ratios between formate salt and silicate salt components. Certain aqueous drilling fluids are specifically exemplified herein, however the person of skill in the art having regard to the teachings herein will recognize that other drilling fluid concentrations and/or ratios may be possible and may be optimized to suit particular applications or parameters. By way of example, concentrations and/or ratios may be optimized based on cost factors and/or based on the characteristics of the particular well being drilled. As well, drilling fluids being used may vary as drilling progresses and conditions change.
In an embodiment, the aqueous drilling fluids described herein may comprise the silicate salt component as a silicate salt solution, and the silicate salt solution may have a concentration in the aqueous drilling fluid of about 0.1% to about 30% v/v, such as about 1%-15 v/v, 1%-10% v/v or 8%-10% v/v.
In another embodiment, the aqueous drilling fluids described herein may comprise a concentration of the silicate salt which is about 0.1%-30% w/v, such as about 1%-15 w/v, 1%-10% w/v or 8%-10% w/v, or may comprise about a 0.1%-30% v/v, such as about 1%-15 v/v, 1%-10% v/v or 8%-10% v/v, concentration of a suitable silicate salt solution.
In still another embodiment, the aqueous drilling fluids described herein may comprise a concentration of the formate salt which is about 85% or more w/v, 90% or more w/v, or may comprise about 90% or more v/v concentration of a suitable formate salt solution.
In another embodiment, the aqueous drilling fluids described herein may comprise a concentration of the formate salt which is about 90%-92% w/v, or may comprise about a 90%-92% v/v concentration of a suitable formate salt solution.
In still other embodiments, the silicate salt component may be a silicate salt solution, and the silicate salt solution may have a concentration in the aqueous drilling fluid of about 0.1%-30%
v/v, such as about 8%-10% v/v.
In another embodiment, the aqueous drilling fluid may comprise from about a 70:30 v/v ratio of formate brine:sodium silicate solution to about 99.9:0.1. In another embodiment, the aqueous drilling fluid may comprise about 85:15 or 92:8 v/v ratio of formate brine:sodium silicate solution. In yet another embodiment, the aqueous drilling fluid may comprise about a 90:10 v/v ratio of formate brine:sodium silicate solution. In still another embodiment, the aqueous drilling fluid may comprise about a 92:8 to about a 90:10 v/v ratio of formate brine:
sodium silicate solution. In another embodiment, the aqueous drilling fluid may comprise about a 92:8 v/v ratio of potassium formate brine:sodium silicate solution. In yet another embodiment, the aqueous drilling fluid may comprise about a 90:10 v/v ratio of potassium formate brine:sodium silicate solution. In still another embodiment, the aqueous drilling fluid may comprise about a 92:8 to about a 90:10 v/v ratio of potassium formate brine:neat sodium silicate solution.
In another embodiment of any of the aqueous drilling fluid or fluids described above, the formate brine may be about 1000kg/m3 (1.00 SG) to about 1500 kg/m3 (1.50 SG), such as about 1250 kg/m3 to about 1400 kg/m3. In still another embodiment of any of the aqueous drilling fluid or fluids described above, the potassium formate brine may be about 1000kg/m3 (1.00 SG) to about 1500 kg/m3 (1.50 SG), such as about 1250 kg/m3.
In a further embodiment of any of the aqueous drilling fluid or fluids described above, such a sodium silicate solution may be about 0.1-50 w/w sodium silicate, such as about 44 wt% sodium silicate in water, or about 44.1 wt% sodium silicate in water. By way of further example, a suitable silicate salt solution may be a sodium silicate salt solution which is about 0.1-50 w/v sodium silicate, such as about 44 wt% sodium silicate in water, or about 44.1 wt% in water.
In yet another embodiment, there is provided herein a process for preparing an aqueous drilling fluid composition as described herein, the process comprising:
providing an aqueous potassium formate brine solution, cesium formate brine solution, or sodium formate brine solution, and mixing a concentrated sodium silicate solution into or with the potassium formate brine solution, cesium formate brine solution, or sodium format brine solution.
In certain embodiments, a concentrated sodium silicate solution suitable for such processes may include a suitable sodium silicate solution as described above, or another suitable sodium silicate solution as will be known to the person of skill in the art having regard to the teachings herein.
In still another embodiment, there is provided herein a process for preparing an aqueous drilling fluid composition as described herein, the process comprising:
providing a water-diluted sodium silicate solution, and mixing a concentrated potassium formate brine or a dry potassium formate salt, a concentrated cesium formate brine or cesium formate salt, or a concentrated sodium formate brine or a sodium formate salt, into or with the sodium silicate solution.
In certain embodiments, a suitable water-diluted sodium silicate solution may include, for example, about an 8% sodium silicate solution as described herein, or another suitable sodium silicate solution as will be known to the person of skill in the art having regard to the teachings herein.
Experimental examples of such processes are described in further detail in Example 2 (below).
In yet another embodiment, there is provided herein a method for drilling a subterranean formation comprising shale, the method comprising:
drilling into the subterranean formation using a drill, thereby forming a wellbore;
and circulating an aqueous drilling fluid as described herein in the wellbore simultaneously or sequentially with drilling, thereby reducing damage to shale surrounding the wellbore caused by swelling or disaggregation in the shale.
In still another embodiment, there is provided herein method for drilling a subterranean formation, the method comprising:
drilling into the subterranean formation using a drill, thereby forming a wellbore;
circulating an aqueous drilling fluid as described herein in the wellbore simultaneously or sequentially with drilling, thereby sealing microfractures in the wellbore and/or the subterranean formation; and recovering at least a portion of the aqueous drilling fluid.
In yet another embodiment, there is provided herein a use of the aqueous drilling fluid as described herein as a shale inhibitor, a fluid loss reduction agent, a drilled formation stabilizer, and/or as a coal stabilizer.
In still another embodiment, there is provided herein a method for stabilizing a drilled formation, the method comprising:
circulating or injecting aqueous drilling fluid or fluids as described above into the drilled formation, thereby stabilizing shale in the drilled formation.
In another embodiment, there is provided herein a method for drilling a subterranean formation comprising shale, limestone, dolomite, sandstone, evaporite, mud stone or coal, the method comprising:
drilling into the subterranean formation using a drill, thereby forming a wellbore; and circulating aqueous drilling fluid or fluids as described above in the wellbore simultaneously or sequentially with drilling, thereby reducing damage to shale, limestone, dolomite, sandstone, evaporite, mud stone or coal surrounding the wellbore caused by swelling or disaggregation.
In still another embodiment, there is provided herein a method for stabilizing a drilled formation, the method comprising:
circulating or injecting aqueous drilling fluid or fluids as described above into the drilled formation, thereby stabilizing shale, limestone, dolomite, sandstone, evaporite, mud stone or coal, in the drilled formation.
In certain embodiments, the subterranean formation and/or the drilled formation may comprise limestone, dolomite, sandstone, evaporite, mud stone, shale, coal, or combinations thereof It will be understood that drilling operations performed at subterranean formations comprising shale may be subject to shale destabilization, which may result in wellbore instability, instability of the subterranean formation, and/or formation of fractures or pores in wellbores and/or the subterranean formation, which may result in fluid loss. Such problems may be encountered, for example, when using aqueous drilling fluids. Without wishing to be bound by theory, water in aqueous drilling fluids may interact with shale and clay components therein, causing swelling and/or disaggregation leading to damage of wellbores and/or subterranean formations.
As a result of these difficulties, drilling operations have traditionally avoided the use of costly drilling fluids when working at subterranean formations where high fluid loss and/or shale instability is expected. Potassium formate brine-based drilling fluids, for example, are typically not used in such applications, as fluid loss may be difficult to control and may result in significant added expense, which may be cost-prohibitive. Example 1 (below) provides an example where potassium formate brine loss resulted in significant added expense. While conventional fluid loss circulation materials and fluid loss additives may be helpful to some degree, fluid loss still represents a significant challenge.
Shale inhibitors and/or shale stabilizers have been developed in the field in an effort to reduce issues arising from shale destabilization. For example, silicate fluids have been used in the field as shale stabilizers. Without wishing to be bound by theory, it is believed that silicate fluids promote shale stabilization by coating shale in a thin layer of precipitated silicate, sealing the shale and/or reactive portions thereof so as to reduce swelling and/or damage.
Such an effect may also result in sealing of microfractures in rock, potentially reducing fluid invasion.
Unfortunately, the introduction of shale stabilization additives to drilling fluids may prove challenging in the field. The addition of shale inhibitors to drilling fluids may have undesirable or unintended consequences, such as formation of precipitants, component instability or loss of function, and/or reduced drilling fluid stability, shelf-life, or operational lifetime.
As described herein, it has surprisingly been found that drilling fluids comprising a silicate salt, such as sodium silicate, in combination with a formate salt, such as potassium formate, provide benefits in terms of shale stability and/or reduced fluid loss via seepage, without significantly interfering with the benefits provided by formate brine-based drilling fluids.
Shale recovery experiments may be useful in assessing shale stabilizing properties of fluids.
Results provided in Example 2 described below indicate that certain drilling fluids as described herein provide excellent shale recovery, with greater than 99% recovery of Pierre shale having been observed under the experimental conditions tested. Recoveries achieved using certain drilling fluids as described herein were better than recoveries obtained from the water, the potassium formate brine solution, the sodium silicate solutions, and the potassium silicate solution tested under the experimental conditions used. Under the conditions tested, sodium silicate and potassium formate were observed as being compatible at least up to a fluid density of 1400 kg/m3, while exhibiting excellent shale stabilization properties.
The person of skill in the art having regard to the teachings herein will understand that drilling fluids as described herein may used in applications beyond the drilling of wellbores. Although fluids are referred to herein as drilling fluids, it will be understood that such drilling fluids may be used in the treatment of already existing wellbores or subterranean formations, for example as drilled formation stabilizers. In such examples, a drilling fluid as described herein may be exposed to, injected into, or circulated in an existing wellbore, a wellbore in progress, or a subterranean formation, so as to provide shale stabilization and/or fluid loss reduction effects to the wellbore or subterranean formation. In such examples, the drilling fluids may be considered as wellbore and/or subterranean formation treatment fluids. As well, it will be recognized that drilling fluids as described herein may additionally be used as additives, which may be added to another compatible aqueous drilling or well-treatment fluid in an amount sufficient to impart shale stabilization and/or fluid loss reduction effects to the compatible aqueous drilling or well-treatment fluid. Drilling fluids as described herein are not limited to drilling applications, and may be useful in other shale treatment, shale stabilization, and/or shale recovery applications as will be recognized by the person of skill in the art having regard to the teachings herein.
It will further be understood by the person of skill in the art having regard to the teachings herein that difficulties similar to those associated with operations involving shale as described above may also be encountered in other subterranean formations comprising, for example, limestone, sandstone, dolomite, evaporite, mud stone or coal. Given the similarities, drilling fluids as described herein may also be useful in certain operations involving limestone, sandstone, or coal, for example, and may function in a related manner in such applications.
One or more illustrative embodiments have been described by way of example. It will be understood to persons skilled in the art that a number of variations and modifications can be made without departing from the scope of the invention as defined in the claims.
EXAMPLE 1: Drilling Fluid Loss The use of potassium formate brines may be an attractive option for drilling operations where a high fluid density is desired, due to the fact that densities in excess of 1500 kg/m3 may be achieved with no weighting material added, allowing for higher rates of penetration, longer lifetimes of downhole equipment, and fewer product additions, which may lead to shorter drilling times and/or less equipment usage, possibly resulting in substantial cost savings.
However, in higher loss zones, it may be very difficult to control the escape of the fluid into the formation, and so because of the high cost of potassium formate brine, failure to control losses may cause the fluid system to become prohibitively In this example (Figure 1) the intermediate and lateral sections of Well 1 were both drilled using potassium formate brine. High seepage losses were encountered (primarily in the intermediate interval) which resulted in an unacceptable cost to the operator. Switching to an oil based drilling fluid in the intermediate sections (Well Groups 2 and 3) resulted in lower seepage losses in this interval ¨ the laterals were still drilled with potassium formate.
This example illustrates the costly effects of failing to control fluid loss when drilling with potassium formate systems.
In an effort to improve shale stabilization and/or fluid loss reduction properties of drilling fluids such as potassium formate brine-based aqueous drilling fluids, it has surprisingly been found herein that drilling fluids comprising a silicate salt, such as sodium silicate, in combination with a formate salt, such as potassium formate, provide benefits in terms of shale stability and/or reduced fluid loss via seepage, without significantly interfering with the benefits provided by formate brine-based drilling fluids. Examples of such drilling fluids, and features thereof, are described in further detail below in Examples 2 and 3.
EXAMPLE 2: Aqueous Drilling Fluids Comprising Potassium Formate and Sodium Silicate, Compatibility Testing Thereof, and Processes for the Preparation Thereof The following example describes the preparation and compatibility testing of examples of aqueous drilling fluids comprising potassium formate and sodium silicate.
Processes for blending sodium silicate and potassium formate are described which allow for formation of stable mixtures for which precipitate formation and other adverse effects were not observed under the conditions tested.
Fluid Formulations:
= 1250 kg/m3 Potassium Formate (K-formate): 38.4 wt% K-formate in DI water = Potassium silicate: Stock solution of 2.5:1 molar ratio of 5i02:K20 = Sodium silicate (used for compatibility testing): Sodium Silicate D from National Silicates (2.0 :1 molar ratio of 5i02:Na20) Procedures of Preparation Processes and Compatibility Testing:

Method 1: 100 mL of 1250 kg/m3 potassium formate brine was prepared by either the addition of the required amount of dry potassium formate salt to DI water or by dilution of stock 75%
potassium formate brine with DI water. 92 mL of the brine was then measured out and 8 mL of sodium silicate solution (44.1 wt% solution of sodium silicate in water) was added, and the mixture was shaken vigorously. The fluid was then left to settle and observed for precipitate formation, and photographs were taken.
Method 2: 12.9 mL of concentrated sodium silicate was added to 87.1 mL of DI
water, and 62 mL of 75% potassium formate brine was added with stirring. The sample was then shaken vigorously to ensure complete mixing and then left to settle and observed for precipitate formation.
By way of example, methods such as these may be used to prepare a drilling fluid comprising 8% v/v sodium silicate solution in potassium formate, the sodium silicate solution itself having a concentration of 44.1 wt% and a density of 1.53g/mL, providing a concentration of sodium silicate in the 8% v/v solution of 5.4g/L of brine, or 5.4 kg/m3.
Compatibility Test Results:
Compatibility testing was performed to determine if, and how, sodium silicate could be combined with potassium formate brine to obtain a fluid density of approximately 1250 kg/m3 and a silicate concentration of 8% v/v. Two approaches were taken (Method 1 and Method 2, above).
The first approach was to add concentrated sodium silicate solution to a 1250 kg/m3 potassium formate, and the second approach was to add potassium formate to an 8%
solution of sodium silicate in water. In the first approach, the 1250 kg/m3 potassium formate brine was prepared both from dilution of a stock concentrated brine as well as by the addition of the dry salt to DI
water, and concentrated sodium silicate solution was added to the brine to obtain a final volume ratio of 92:8 brine:silicate.
In the second approach, an 8% sodium silicate solution was prepared by diluting the concentrated sodium silicate with DI water, and then either dry potassium formate or concentrated potassium formate was added to achieve a fluid density of 1250 kg/m3.
Figure 2 shows a representative sample of a 92:8 v/v 1250 kg/m3 potassium formate brine:
sodium silicate solution. As shown, the fluid remained clear and colourless, with no signs of precipitate formation, indicating excellent compatibility.
EXAMPLE 3: Aqueous Drilling Fluids Comprising Potassium Formate and Sodium Silicate, Shale Stabilization and Dispersion Testing Thereof The following example describes examples of aqueous drilling fluids comprising potassium formate and sodium silicate, and the effectiveness thereof in shale stabilization and shale recovery.
Shale recovery experiments as described herein are useful in assessing shale stabilization of drilling fluids. Because drilling fluids comprising silicate are believed to function by coating shale in a thin layer of silica/silicate, effective shale recovery/shale stabilization results suggest that shale is being effectively coated and therefore suggests that effective drilling fluids may also be able to seal microfractures. This type of testing has been previously used for potassium silicate fluid, and the results obtained were validated in the field.
Fluid Formulations:
= 10% Ecodrill 246-T1 sodium silicate solution (2:1 5i02:Na20 ratio) = 10% Ecodrill 120 sodium silicate solution (1.8:1 5i02:Na20 ratio) = 90/10 1250 kg/m3 potassium formate/Ecodrill 246-T1 = 90/10 1250 kg/m3 potassium formate/Ecodrill 120 = 90/10 1250 kg/m3 potassium formate/DI water = 10% potassium silicate solution Procedure for Shale Recovery and Shale Dispersion Testing:

Pierre shale was ground to +10/-20 mesh size, and 20 g portions were weighed out and transferred into hot roll cells. 300 mL of each test fluid listed above was added to the cells, and the samples were hot rolled at 60 C for 16 hours. The shale was collected on a 40 mesh screen, rinsed with 5% KC1 and then a small volume of DI water, and then dried in a 110 C oven. Once fully dried, the samples were weighed and the percent recovery determined.
Shale Recovery and Shale Dispersion Testing Results:
Table 1 (below), and Figure 3, show the results for the shale dispersion testing with various mixtures of sodium silicate, using DI water and 10% potassium silicate as points of reference.
As shown, when no inhibitor is present (i.e., the DI treatment), the shale falls apart to a significant extent, with only about 15% of the shale being recovered. The potassium formate brine on its own provides substantial stability (about 83.6% recovery), likely due to the high concentration of potassium ions, but the two samples of sodium silicate in DI
water (10%
Ecodrill 246-T1 in DI water, and 10% Ecodrill 120 in DI water) provided a higher degree of stability, with recoveries of 96.9% and 95.0%, respectively. These recoveries are very similar to those of potassium silicate (97%), which is often considered the gold standard for shale inhibition in water-based drilling fluids. These results suggest that switching from a potassium to a sodium silicate should have a negligible impact on shale stability.
When the mixed sodium silicate and potassium formate fluid systems (90:10 1250kg/m3 K-formate:Ecodrill 246-T1, and 90:10 1250 kg/m3 K-formate:Ecodrill 120) were used, shale recovery was increased to near-quantitative, providing above 99% for both (99.5% and 99.1%, respectively).
Table 1: Shale Dispersion/Shale Recovery Testing Results with K-Formate and/or Silicate Fluids Fluid Initial Final mass (:)/0 Recovery mass (g) (g) DI water 20.00 3.00 15.0 90:10 1250 kg/m3 K-Formate:DI water 20.00 16.71 83.6 10% Ecodrill 246 in DI water 20.01 19.38 96.9 10% Ecodrill 120 in DI water 20.02 19.01 95.0 90:10 1250 kg/m3 K-formate:Ecodrill 246-T1 20.02 19.92 99.5 90:10 1250 kg/m3 K-formate:Ecodrill 120 20.01 19.83 99.1 Potassium silicate 20.03 19.42 97.0 Collectively, these results suggest that shale stabilization properties and/or fluid loss reduction properties can be introduced to potassium formate brine-based drilling fluids without significant adverse effects by combination with sodium silicate. The examples herein describe the preparation of fluid systems using two different approaches, either by mixing concentrated sodium silicate into, for example about a 1250 kg/m3 potassium formate brine, prepared either from a stock concentrate or dry salt and DI water, or by adding concentrated potassium formate brine or potassium formate salt to a diluted sodium silicate solution. Sodium silicate on its own was found to be more effective at shale inhibition than potassium formate brine under the conditions tested, and had comparable performance to potassium silicate. The mixed sodium silicate-potassium formate fluid was found to be even more effective under the conditions tested, with over 99% shale recovery being observed.
It will be appreciated that although a 1250 kg/m' potassium formate brine drilling fluid and drilling fluid systems were exemplified, other concentrations are also within the scope of the invention and the invention should not be limited to a 1250 kg/m' potassium formate brine based drilling fluid. This embodiment is for illustrative and exemplary purposes and is not intended to be limiting.
EXAMPLE 4: Potassium Formate and Sodium Silicate Fluid System The use of sodium/potassium silicate additives in potassium formate brine was investigated. All of the potassium silicate materials tested were found to be incompatible with potassium formate.
However, certain sodium silicate additives were found to be compatible and additional testing was conducted in order to determine if the resulting sodium silicate ¨
potassium formate system could be used in drilling fluid applications. The system was found to be stable within specific operating parameters and was recommended for field trial under controlled conditions.
The primary objective of this project was to develop a fluid loss additive for use in potassium formate brines. Solids free (flocculated) potassium formate brines have received considerable attention as high performance drilling fluids in Western Canada over the past five years. These brines offer high densities combined with high rates of penetration (ROP) and prolong drill bit life. However, as outlined above, the solids free nature of the brines can result in high seepage loss volumes which can be cost prohibitive due to the high cost of potassium formate.
This experimentation investigates the use of sodium and/or potassium silicates as potential fluid loss additives for use in potassium formate brines. The results are presented in the Results and Experimentation section below.

Results and Experimentation Product Compatibility Matrix Previous testing demonstrated an incompatibility between potassium silicate (various grades) and potassium formate brine (various densities). However, preliminary results indicated that certain grades of sodium silicate were potentially compatible with potassium formate.
These findings were investigated in more detail and the results are summarized in Table 2.
These tests were performed at room temperature and a simple pass/fail assigned to each compatibility test. A pass indicates that no precipitate was observed when the two products were combined. Conversely, samples that produced a visible precipitate were assigned a fail designation.
Table 2 - Compatibility Testing at Room Temperature Potassium Formate Density Sodium Time 1500 Silicate Period 1200 kg/m3 1300 kg/m3 1400 kg/m3 kg/m3 10% M Initial PASS FAIL FAIL FAIL
10%M 20h PASS FAIL FAIL FAIL
20% M Initial PASS FAIL FAIL FAIL
20%M 20h PASS FAIL FAIL FAIL
10%D Initial PASS PASS PASS FAIL
10%D 20h PASS PASS PASS FAIL
20%D Initial PASS PASS PASS FAIL
20%D 20h PASS PASS PASS FAIL
10% BW-50 Initial PASS PASS PASS PASS
10% BW-50 20h PASS PASS PASS FAIL
20% BW-50 Initial PASS PASS PASS PASS
20% BW-50 20h PASS PASS PASS FAIL
Three different grades of sodium silicate we used in testing and the specifications of these materials are summarized in Table 3. (All three materials were provided by National Silicates).

Table 3 - Sodium Silicate Specifications Sodium Silicate Type Specifica tion M D BW-50 Si02:Na2 0 2.58 2 1.6 % Na2O 12.4 14.7 16.5 % SiO2 32.1 29.4 26.2 pH 11.8 12.8 13.5 Density (g/cm3) 1.5 1.53 1.53 The results in Table 2 indicate that all three grades of sodium silicate exhibit some stability in potassium formate brine. The maximum stable brine density using Sodium Silicate ¨ M was 1200 kg/m3. Switching to Sodium Silicate ¨ D extended the stable brine density up to 1400 kg/m3 and Sodium Silicate ¨ BW50 exhibited partial (short-term) stability at a brine density of 1500 kg/m3.
Based on these results, Sodium Silicate BW-50 was the preferred product as it offered stability over the widest potassium formate brine density. However, it was decided that the high pH of this product (13.5) could pose a potential concern for workers handling the sodium silicate BW-50. The Sodium Silicate ¨ D was stable in brine densities up to 1400 kg/m3 and had a lower pH.
It was decided that this product offered a more acceptable balance of performance and worker safety and this product was used in all subsequent testing.
In order to further investigate the stability of the Sodium Silicate ¨ D in potassium formate brine a series of compatibility tests were performed at elevated temperatures and the results are summarized in Table 4. (Testing was performed at a brine density of 1400 kg/m3). The system was stable (no precipitation) at temperatures up to 150 C.

Table 4 - High Temperature Testing with Sodium Silicate - D
Sodium Brine Silicate Density Time Period Temperature Stability 10%D 1400 kg/m3 24h 50 C PASS
20%D 1400 kg/m3 24h 50 C PASS
10%D 1400 kg/m3 24h 100 C PASS
20%D 1400 kg/m3 24h 100 C PASS
10%D 1400 kg/m3 24h 150 C PASS
20%D 1400 kg/m3 24h 150 C PASS
To investigate the influence of pressure on the stability of the system, HTHP
testing was performed. In this test a fluid sample containing 10% Sodium Silicate ¨ D in potassium formate brine (1400 kg/m3) was pressurized to 6000 psi with nitrogen gas and heated to 150 C. The sample was aged under these conditions for 24h and then visually inspected for signs of precipitate formation. The results are summarized in Table 5 - no significant precipitation was observed.
Table 5 - HTHP Testing with Sodium Silicate - D
Sodium Brine Silicate Density Time Period Temperature Pressure Stability 10%D 1400 kg/m3 24h 50 C 6000 psi PASS
It was of interest to identify the chemical composition of the precipitate formed between Sodium Silicate ¨ D and 1500 kg/m3 potassium formate. Unfortunately, preliminary analysis using XRD
and EDS analysis failed to identify the precipitate species. This analysis will be pursued in future work.
Health and Safety As discussed above, three different grades of sodium silicate were screened for stability in potassium formate brines of various densities (1200 kg/m3 ¨ 1500 kg/m3). The specifications of these products are summarized in Table 3. While Sodium Silicate BW-50 offered maximum stability it was decided that the pH of this product (13.5) was potentially too high to be used in drilling fluid applications as it could decrease the level of worker safety.
The Sodium Silicate ¨

D exhibited acceptable stability in potassium formate brine and possessed a lower pH of 12.8. It was decided to use Sodium Silicate ¨ D in all subsequent testing. While the pH
of the Sodium Silicate ¨ D is lower than Sodium Silicate ¨ BW-50 the product is still classified as corrosive under the WHIMIS system and it is noted that extra caution will need to be applied if using bulk volumes of this material in field operations.
Flocculation Testing for Clear Brine/Solids Free System As discussed above, the objective of this project was to develop a fluid loss additive for use in solids free potassium formate brines. The drilled solids in these systems are removed by a surface flocculation process. It was therefore important to ensure that Sodium Silicate ¨ D did not negative impact the flocculation process. A series of flocculation experiments were performed and the results are summarized in Table 6 and Figures 4 and 5. In these experiments, a mixture of rev-dust (25 kg/m3) and bentonite (5 kg/m3) was used to mimic drilled solids and the performance of three common flocculation polymers was evaluated in a 1400 kg/m3 potassium formate brine in the absence or presence of 10% Sodium Silicate ¨ D.
The flocculation polymers were pre-hydrated in fresh water and tested at an effective concentration of 0.1 kg/m3.
Table 6 - Flocculation Testing Hyperdrill Fluid System Observation Hyperdrill 204RD
Hyperdrill NF301H CP905H
Flocculation (Y/N) YES YES YES
1400 kg/m3 Potassium Formate Rank* 1 2 3 1400 kg/m3 Potassium Formate Flocculation (Y/N) YES
YES YES
10% Sodium Silicate - D Rank* 1 2 3 *Flocculation Rank: 1 = Best Performance The data in Table 6 indicates that Sodium Silicate ¨ D does not negatively impact the flocculation of a 1400 kg/m3 density potassium formate brine. Under these specific test conditions, Hyperdrill 204RD provided the best performance in both fluid systems. However, the optimum flocculation polymer under field conditions will depend on numerous variables and onsite pilot testing is strongly recommended. It is interesting to note that the control experiment for the fluid containing 10% Sodium Silicate ¨ D (no flocculant) exhibited faster solids settling than the pure 1400 kg/m3 potassium formate brine.
Corrosion Control High corrosion rates can be a problem in brine based drilling fluids.
Fortunately, corrosion rates in potassium formate brines are low and the addition of corrosion inhibitors is not required. It was important to confirm if the sodium silicate ¨ potassium formate system behaved similarly and so a series of electrochemical corrosion tests were performed.. The test parameters are detailed below and the results summarized in Table 7.
Test Conditions:
Test Duration: 24h Temperature: 50 C
Electrode Rotation Rate: 2500 rpm Working Electrode: AISI 1018 carbon Steel Purge Gas: Compressed Air Table 7 - Corrosion Testing Results Fluid System Initial LPR (mpy) Final LPR (mpy) Weight Loss (mpy) Potassium Formate (1363 kg/m3) 0.06 0.02 1.83 Potassium Formate (1363 kg/m3) 10% Sodium Silicate D 0.04 0.03 2.44 The electrochemical (LPR) and weigh loss corrosion rates in Table 7 were low for both fluids which indicates that Sodium Silicate ¨ D does not increase the corrosion rate of the potassium formate brine. This results was expected as soluble silicates have been used as corrosion inhibitors in various applications.
Depletion Testing on Sodium Silicate ¨ D
It was of interest to explore the possibility of removing Sodium Silicate ¨ D
from the silicate ¨
formate system in a controlled manor. A series of tests were performed using calcium chloride as the 'striping agent' and the results are summarized in Table 9.

Table 8 - Depletion of Sodium Silicate - D using Calcium Chloride Parameter 1400 kg/m3 Potassium Formate + 10% Sodium Silicate D
CaCl2.2 H20 (kg/m3) 0 5 10 25 Density (kg/m3) 1417 1384 1381 1374 pH 13.4 13.4 13.3 12.1 Si02 (kg/m 3) 40.2 25.7 15 1.2 Na20 (kg/m 3) 21.1 13.8 8.3 0.7 Si02:Na20 1.9 1.9 1.8 1.7 Sodium Silicate 9.2 5.9 3.5 0.3 (Volume %) Depletion (%) 0 35.9 62 96.7 Based on the data in Table 8 an approximate formula was composed for calculating the amount of calcium chloride required to precipitate a given volume of Sodium Silicate -D from the system.
To Remove > 90% of Sodium Silicate - D use 2.5 kg/m3 CaC12.2 H20 per 1% Sodium Silicate -D
A second round of testing was performed in order to validate this calculation and the results are summarized in Table 9. A solution containing 5% Sodium Silicate -D was treated with 11.5 kg/m3 of calcium chloride dihydrate (calculated from formula). The treatment precipitated approximately 94% of the Sodium Silicate - D which confirmed the effectiveness of this method and treatment calculator.
Table 9- Depletion of Sodium Silicate - D using Calcium Chloride Parameter 1400 kg/m3 Potassium Formate + 5% Sodium Silicate D
CaCl2.2 H20 (kg/m3) 0 11.5 Density (kg/m3) 1403 1384 pH 13.3 12.4 Si02 (kg/m3) 20 1.2 Na2O (kg/m3) 10.8 0.8 Si02:Na20 1.9 1.5 Sodium Silicate 4.6 0.3 (Volume %) Depletion (%) 0 93.5 Field Test for Carbonate / Bicarbonate in Potassium Formate As discussed above, it is useful to know the concentration of bicarbonate ions present in the potassium formate brine used in the sodium silicate ¨ potassium formate system. Elevated levels of bicarbonate ions (> 1000 mg/L) reduce the stability of the system and result in the precipitation of insoluble species. It was therefore important to develop a simple field test for measuring the concentration of bicarbonate / carbonate ions in potassium formate brine.
Fortunately, Cabot Speciality Fluids published such a test in their Formate Technical Manual.
This method uses a pH measurement and acid-base titration in combination with a set of calculations which have been incorporated into as simple Excel spreadsheet.
The accuracy of this procedure was confirmed by a series of QA/QC experiments on potassium formate brines containing known concentrations of bicarbonate/carbonate (Table 10).
Table 10 - Evaluation of Bicarbonate! Carbonate Field Test Procedure Calculated Measured Test Fluid Bicarbonate (mg/L) Test Accuracy Final pH Bicarbonate (mg/L) 50% Potassium Formate (#5) N/A 800 N/A 12 0 #5 + 8.21 kg/m3

5,800 5,600 +/- 200 mg/L 10.2 KHCO3 15,238 #5 + 16.41 kg/m 3 10,800 10,600 +/- 200 mg/L 11.6 KHCO3 15,238 Field Trial A field trial was conducted on this system with a Western Canadian Operator in October 2016.
The results from this trial have been documented and are outlined in Example 5.
EXAMPLE 5: FIELD TRIAL
A field trail was conducted on a potassium formate + sodium silicate drilling fluid system.
Quality Control on Potassium Formate As described previously it is preferred that the potassium formate used in this system contains only low levels of bicarbonate anions (ideally < 500 mg/L). As part of the QA/QC program the carbonate/bicarbonate levels were measured in all potassium formate delivered to location. The results from this testing are summarized in Table 11. All potassium formate samples passed QA/QC analysis.
Table 11 - QA/QC Analysis on Potassium Formate Carbonate Bicarbonate Date Received Density (kg/m) pH (mg/L) (mg/L) Pass/ Fail 8-Oct-16 1570 13.3 1392 444 PASS
11-Oct-16 1560 13.1 288 178 PASS
14-Oct-16 1575 14.8 763 101 PASS
In addition to the analysis reported in Table 11, a visual check for the chemical compatibility between the potassium formate and Sodium Silicate ¨ D was also performed. The results from this testing are summarized in Table 12.
Table 12 - QA/QC Analysis on Potassium Formate Date Received Compatibility Test Observation Pass/ Fail 1300 kg/m3 Potassium Formate +
8-Oct-16 10% Sodium Silicate ¨ D Very Slight Precipitate PASS
1400 kg/m3 Potassium Formate +
8-Oct-16 10% Sodium Silicate ¨ D Slight Precipitate PASS
1300 kg/m3 Potassium Formate +
11-Oct-16 10% Sodium Silicate ¨ D No Precipitate PASS
1400 kg/m3 Potassium Formate +
11-Oct-16 10% Sodium Silicate ¨ D Very Slight Precipitate PASS
1300 kg/m3 Potassium Formate +
14-Oct-16 10% Sodium Silicate ¨ D No Precipitate PASS
1400 kg/m3 Potassium Formate +
14-Oct-16 10% Sodium Silicate ¨ D Very Slight Precipitate PASS
Flocculation Process Flocculation pilot testing was carried out throughout the field trial in order to aid flocculation polymer selection. The polymers included in testing are detailed in Table 13.

Table 13 - Flocculation Polymers used in Pilot Testing Molecular Weight Product Charge Density (Million) Hyperdrill AF 204 Anionic ¨ 10% 15 Hyperdrill AF 207 Anionic ¨ 30% 10 Hyperdrill AF 247 Anionic ¨ 30% 4 ¨ 5 Hyperdrill NF 301 Non-Ionic 10 Magmafloc 351 Non-Ionic 10 Hyperdrill OP 905 Cationic¨ 10% 5 Hyperdrill OP 911 Cationic ¨ 80% 5 ¨ 7 Hyperdrill OP 944 Cationic¨ 10% 1.4 The actual flocculation polymers used throughout the well are summarized Table 14 along with measured solids concentration in the drilling fluid. (Care should be taken not to interpret the reported solids values as a direct measure of polymer performance since centrifuge performance and drilling operations also impact this parameter). Overall, the data demonstrates that good flocculation performance was maintained throughout the field trail.
Table 14 - Flocculation Polymers used in Pilot Testing Flocculation Approximate Depth (m) Polymer Solids (Volume %) 1804- 2072 Hyperdrill OP 911 Trace ¨0.8 2072 -2790 Hydrofloc 0.8¨ 1.1 2790 -2845 Hyperdrill NF 301 Trace - 1.1 2845 -2947 Hyperdrill OP 905H Trace ¨ 0.4 2947 ¨ 2959" Hyperdrill AF 247 Trace 2959 -4449 Hyperdrill OP 905H Trace ¨0.8 * Laboratory Testing Indicated CP 905H ¨ AF 247 run as Field Trail (Performance =
Modest) Protection of Surface Equipment The accretion of Sodium Silicate ¨ D onto drilling rig surface equipment was a concern based on previous experience. This was explained to the rig crew and RIGMATE
(protective wax coating) was applied to the rig at twice the standard loading prior to drilling commencing. This approach appeared to work well as no significant accretion was observed during the duration of the field trail.

Compatibility with Downhole Tools Testing by a third party laboratory confirmed the compatibility of the drilling fluid with the downhole tool elastomers to be used on the well. No significant elastomer problems were reported on the field trial.
Compatibility of Drilling Fluid with Mud Pump Components A series of mud pump piston failures were encountered throughout the well. The original pistons were polyurethane Patriot SA pistons manufactured by Supreme Manufacturing.
Discussion with the manufacturer indicated that these pistons were not designed for use high salinity solids free WBM fluids.
Several Caliber BN polyurethane pistons from Premium Oilfield Technologies were also tested but also failed over short service periods. The manufacturer confirmed that these pistons are designed for oil based drilling fluids and not recommended for use in water based systems. The manufacturer recommended Caliber X400 pistons as a possible candidate but these were not available for the current field trail.
Finally, a series of Black Cat nitrile type pistons from SouthWest Oilfield Products were tested.
These pistons provided improved lifetime over the polyurethane pistons detailed above and were used for the remainder of the field trial. These preliminary tests indicate that nitrile type pistons should be used with the drilling fluid in question but further research into this topic is suggested.
Conclusions Sodium Silicate ¨ D was stable in potassium formate brine (density range 1285 ¨ 1310 kg/m3).
The rig crew were able to safely handle this high pH fluid system and no health and safety incidents/concerns were reported during the field trail.
Pilot testing allowed a good flocculation polymer to be identified and used throughout the field trial. In combination with surface equipment setup and centrifuge optimization the drilling fluid solids concentration was maintained at an acceptable level.

The accrection of Sodium Silicate ¨ D onto surface equipment was sucessfully controlled by the application of RIGMATE (protective wax coating) prior to starting the drilling operation. The compatability of the drilling fluid with downhole tool elastomers had been tested previously and no significant issues were encountered during the field trial. However, a series of mud pump piston failures were encountered throughout the well. Preliminary observations indicate that nitrile type pistons provide the best performance in this drilling fluid but more research is required on this topic.
Operational Review of Field Trial Overall the original goals for the system were achieved and the well was deemed a qualified success. Elevated torque and drag values were observed in the lateral. ROP
increases were observed throughout the section and compared to the analogous well drilled on the same pad with invert there was an overall 48% increase in instantaneous ROP. No issues with hole conditions or tight hole were reported while drilling or tripping until the very end of the well when a change in lithology was observed and hole conditions near the bit were unstable.
Equivalent Circulating Density (ECD) was monitored and was 30 kg/m3 less than the average ECD on comparable wells drilled with invert emulsion systems. Seepage losses were monitored and were comparable to the invert wells in the area.
Non-limiting examples have been described herein for illustrative purposes intended for persons of skill in the art. All examples and embodiments provided herein should be viewed as non-limiting, and it will be understood that a number of variations and modifications may be made without departing from the scope of the invention as defined in the claims.

Claims

WHAT IS CLAIMED IS:

1. An aqueous drilling fluid comprising:
a formate salt; and a silicate salt.

2. The aqueous drilling fluid of claim 1, wherein the formate salt is potassium formate, cesium formate, or sodium formate.

3. The aqueous drilling fluid of claim 1 or 2, wherein the silicate salt is sodium silicate.

4. The aqueous drilling fluid of any one of claims 1-3, wherein the silicate salt is sodium silicate haying about a 0.5:1 to about a 4:1 wt:wt ratio of SiO2:Na2O, such as a 2:1 SiO2:Na2O ratio, or a 1.8:1 SiO2:Na2O ratio.

5. The aqueous drilling fluid of any one of claims 1-4, wherein the aqueous drilling fluid is a potassium formate brine-based drilling fluid, a cesium formate brine-based drilling fluid, or a sodium formate brine-based drilling fluid.

6. The aqueous drilling fluid of claim 5, wherein a fluid density of the potassium formate brine, the cesium formate brine, or the sodium formate brine is about 1000kg/m3 (1.00 SG) to about 1500kg/m3 (1.50SG).

7. The aqueous drilling fluid of claim 5, wherein a fluid density of the potassium formate brine, the cesium formate brine, or the sodium formate brine is about 1200kg/m3 (1.2 SG) to about 1500kg/m3 (1.50SG).

8. The aqueous drilling fluid of claim 5, wherein a fluid density of the potassium formate brine, the cesium formate brine, or the sodium formate brine is about 1000 kg/m3 to about 1400 kg/m3.

9. The aqueous drilling fluid of claim 5, wherein the aqueous drilling fluid is a potassium formate brine-based drilling fluid haying a fluid density of about 1400 kg/m3 and the silicate salt is a sodium silicate.

10. The aqueous drilling fluid of any one of claims 1-9, wherein the silicate salt component is a silicate salt solution, and the silicate salt solution has a concentration in the aqueous drilling fluid of about 0.1%-30% v/v.

11. The aqueous drilling fluid of claim 10, wherein the silicate salt solution has a concentration in the aqueous drilling fluid of about 1%-15% v/v.

12. The aqueous drilling fluid of claim 10, wherein the silicate salt solution has a concentration in the aqueous drilling fluid of about 1%-10% v/v.

13. The aqueous drilling fluid of claim 10, wherein the silicate salt solution has a concentration in the aqueous drilling fluid of about 8%-10% v/v.

14. The aqueous drilling fluid of any one of claims 1-9, wherein the aqueous drilling fluid comprises from about a 99.9:0.1 v/v ratio of formate brine: sodium silicate solution to about 70:30 v/v ratio of formate brine: sodium silicate solution.

15. The aqueous drilling fluid of any one of claims 1-9, wherein the aqueous drilling fluid comprises about a 85:15, 92:8, or a 90:10, v/v ratio of 1250 kg/m3 ¨ 1400 kg/m3 potassium formate brine: sodium silicate solution.

16. The aqueous drilling fluid of any one of claims 1-9, wherein the aqueous drilling fluid comprises about a 90:10 v/v ratio of formate brine: sodium silicate solution.

17. The aqueous drilling fluid of any one of claims 10-14, wherein the sodium silicate solution is about 0.1-50 w/v sodium silicate, such as about 44 wt% sodium silicate in water.

18. The aqueous drilling fluid of any one of claims 1 to 17, wherein the drilling fluid is a clear brine system substantially free of solids.

19. The aqueous drilling fluid of any one of claims 1 to 17, wherein the drilling fluid is a drilling mud and further comprises a fluid loss polymer and/or a viscosity control polymer.

20. A process for preparing an aqueous drilling fluid as defined in any one of claims 1-19, the process comprising:
providing an aqueous potassium formate brine solution, cesium formate brine solution, or sodium formate brine solution, and mixing a concentrated sodium silicate solution with the potassium formate brine solution, cesium formate brine solution, or sodium formate brine solution;
or providing a water-diluted sodium silicate solution, and mixing a concentrated potassium formate brine or a potassium formate salt, a concentrated cesium formate brine or a cesium formate salt, or a concentrated sodium formate brine or a sodium formate salt, with the sodium silicate solution.

21. A method for drilling a subterranean formation comprising shale, limestone, dolomite, sandstone, evaporite, mud stone or coal, the method comprising:
drilling into the subterranean formation using a drill, thereby forming a wellbore;
and circulating an aqueous drilling fluid as defined in any one of claims 1-19 in the wellbore simultaneously or sequentially with drilling, thereby reducing damage to shale, limestone, dolomite, sandstone, evaporite, mud stone or coal surrounding the wellbore caused by swelling or disaggregation.

22. A method for drilling a subterranean formation, the method comprising:
drilling into the subterranean formation using a drill, thereby forming a wellbore;
circulating an aqueous drilling fluid as defined in any one of claims 1-19 in the wellbore simultaneously or sequentially with drilling, thereby sealing microfractures in the wellbore and/or the subterranean formation; and recovering at least a portion of the aqueous drilling fluid.

23.
Use of the aqueous drilling fluid defined in any one of claims 1-19 as a shale inhibitor, a fluid loss reduction agent, a drilled formation stabilizer, and/or a coal stabilizer.