WO2019222767A1

WO2019222767A1 - Loss control additive for invert emulsion drilling fluids using palygorskite/sepiolite clays

Info

Publication number: WO2019222767A1
Application number: PCT/US2019/036627
Authority: WO
Inventors: Thomas W. POWELL
Original assignee: Rheominerals Inc.
Priority date: 2018-05-12
Filing date: 2019-06-11
Publication date: 2019-11-21

Abstract

A minimally processed, organically modified Palygorskite/Sepiolite clay with its matted morphology to be used as a Fluid Loss Control additive for invert emulsion drilling fluids. A secondary attribute of the specially processed clay is an improvement in the low shear rheology of the invert drilling fluid, thereby improving the suspension of cuttings and weighting agents such as barite. While the invention may be based upon all minimally processed Palygorskite and Sepiolite clay minerals, including both Attapulgite and Sepiolite, the preferred embodiment is based upon the more highly matted Sepiolite clay mined in Amargosa Valley, NV. This invention includes both pre-treated Palygorskite/Sepiolite clays and 'in-situ' modified clays.

Description

LOSS CONTROL ADDITIVE FOR INVERT EMULSION DRILLING FLUIDS USING PALYGORSKITE/SEPIOLITE CLAYS

FIELD OF INVENTION

The field of invention comprises an additive to reduce (high Temperature High

Pressure) HPHT fluid loss in invert emulsion drilling fluids used in drilling subterranean wells.

BACKGOUND OF INVENTION

Drilling fluids (commonly called mud) are pumped under pressure through a long series of connected sections of pipe, known as the drill string. The drill bit is attached to the end of the drill string. As the drill string rotates, the drill bit cuts into the earth and the drilling mud travels down through the drill string and exits through nozzles in the drill bit. The drilling mud then travels upward through the small space between the outside of the drill string and the borehole wall. This space is known as the annulus. Once out of the ground, cuttings are removed, and the mud is amended in the mud tank (or mud pit) to maintain properties. The mud is then recirculated back into the well via the drill string.

The main functions of drilling fluids include: providing hydrostatic pressure to prevent formation fluids from entering into the well bore resulting in a blowout, cooling the drill bit, lubricating the drill bit, cleaning the borehole during drilling, transporting drill cuttings, and suspending the drill cuttings while drilling is paused and while sections of pipe are added to the drill string, known as tripping. Drilling HPHT wells poses a big challenge in the oil and gas industry. Wells with bottom hole static temperature (BHST) and bottom hole static pressure(BHSP) more than 300 deg. F and above 10,000 psi respectively are considered by the industry to be HPHT wells. Invert emulsion fluids are preferred compositions for HPHT drilling. A Fluid Loss Control additive is typically employed in invert drilling fluid

compositions to minimize the fluid loss to the formation that can occur during the drilling process due to the movement of fluids through the borehole wall. Drilling fluids are suspensions of weight materials in an aqueous or non-aqueous suspending medium (carrier) that contain various additives to control fluid properties such as rheology, fluid loss, shale inhibition and lubricity. Invert emulsions are a class of drilling fluids in which a brine (aqueous solution of sodium chloride, calcium chloride, etc.) is the dispersed phase and an organic liquid such as mineral oil, synthetic olefin, synthetic ester, or diesel is the continuous phase. An invert emulsion fluid is particularly useful for drilling high pressure/high temperature wells. Invert fluids are also useful for deviated drilling (horizontal) due to their lubricity and are used for drilling through shale formations to not swell the water sensitive shale. An invert fluid typically contains base oil, brine, weighting materials (typically barite), emulsifiers, oil wetting agents, rheological additives, and fluid loss control additives. Invert-emulsion muds can be run with 5 to 50% water in the dispersed phase, although there are special systems that are 100% oil. An 80:20 oil: water ratio (OWR) being typical. During circulation, a drilling fluid is subjected to wide range of shear rates from virtually no shear in the mud pit to 10³/sec in the drill string and as high as 10⁵/sec exiting the nozzles of the drill bit. In the event of stalled pumping, shear rates can drop to zero. As it circulates downhole, the mud needs to perform all the previously outlined functions throughout the entire shear profile. A discussion on rheology performance of drilling fluids is presented in A. Tehrani, Behavior of Suspensions and Emulsions in Drilling Fluids, ANNUAL TRANSACTIONS OF THE NORDIC RHEOLOGY SOCIETY, VOL.15, 2007 and is included herein by reference. A drilling fluid is a thixotropic system; that is, it exhibits relatively low viscosity when sheared, such as upon agitation or circulation (as by pumping) but, when such shearing action is halted, the fluid thickens to hold cuttings in place. The fluid must become thick rapidly, reaching a sufficient gel strength before suspended materials settle - and this behavior must be totally reversible at all temperatures encountered. In addition, during circulation, the fluid must retain a sufficiently high viscosity to transport the cuttings from the bottom of the hole back to the surface. Clays are important rheological additives for aqueous drilling fluids and organoclays are important rheological additives for invert emulsions. Clay minerals are hydrous aluminum phyllosilicates. Classification of silicates shown below is presented in Bailey SW (1980a) Structures of layer silicates. In: Brindley GW & Brown G ed. Crystal structures of clay minerals and their X-ray identification. London, Mineralogical Society, pp 1–123 (Monograph No.5) and incorporated herein by reference. Clay minerals can be classified as either 1:1 or 2:1.

A 1:1 clay would consist of one tetrahedral sheet and one octahedral sheet, and examples would be kaolinite. A 2:1 clay consists of an octahedral sheet sandwiched between two tetrahedral sheets, and an example is mica. Different sheeting arrangements with different ions sandwiched between such 1:1 or 2:1 structures give rise to different classes of clay such as kaolinite, mica, talc chlorite, vermiculite and smectite clays. Attapulgite and Palygorskite are synonymous terms and are used

interchangeably. Sepiolite Mg4Si6O15(OH)2·6H2O or Attapulgite (Mg,Al)2Si4O10(OH) · 4(H2O) are 2:1 clays. Sepiolite and Palygorskite have similar fibrous or ribbon like or lath-like morphologies and have long water channels and tunnels internal to their structure. Rectangular channels, which contain some exchangeable Ca and Mg cations and zeolitic water, lie between the ribbons, and molecules of bound water lie at the edges of the ribbons. The tubular structure forms ribbons and the ribbons can further get agglomerated into rods. Depending on conditions, a lath assembled from these fibers/ribbons/rods and several layers of lath get assembled atop each other to form a dense matting like papier-mache constructions. Clays are also classified by their water absorptivity and the accompanying swelling. Smectites (such as bentonite) absorb a large amount of water and are high swelling. Sepiolite and attapulgite absorb water, but do not swell due to their unique structure. The morphology and microstructure of Sepiolite clays is well catalogued in the paper“A micromorphological study on natural and folded Sepiolite” by M. Suarez in Eur. J. Mineral, 2015, 27, 81–90, and is incorporated by reference herein. It describes fibrous structures, rods and their microstructures as a function of their water content.

Fluid Loss is the leakage of the invert drilling fluid into the formation. The resulting buildup of solid material (primarily cuttings and weighting material) along the borehole wall is known as“filter cake”. A thin and cohesive filter cake is desirable. Fluid loss is undesirable as it increases the operational cost of drilling. Fluid loss is aggravated by high pressure and high temperature bottom hole conditions. Fluid loss needs to be eliminated or minimized by the addition of a Fluid Loss Control Additive to an invert mud formulation. At the same time the other performance properties of the drilling fluid composition must be acceptable. The rheology of an invert drilling fluid is measured using a Fann™ Viscometer and the following critical values are measured or calculated from the Fann readings: • Plastic Viscosity (PV)

• Yield Point(YP)

• 10 second and 10 minute Gels Emulsion stability (ES) is also critical. The performance attributes of a drilling fluid composition are measured as described below. Rheology- The flow properties of the drilling fluid (rheology) are extremely important. The drilling fluid engineer (mud engineer) constantly checks the rheological profile of the drilling fluid over a range of shear rates using a concentric cylinder Fann™ Viscometer. The ideal drilling fluid has minimal high shear rate viscosity, measured at the 600 rpm Fann rotational speed, and low shear rate viscosity sufficient for suspension properties measured at the 3 rpm Fann rotational speed. This rheological profile allows the invert fluid to be easily pumped and circulated while maintaining suspension of weighting materials and cuttings during periods of no fluid movement such as when tripping pipe and during mechanical breakdowns. The Brookfield™ Viscometer is a widely used industrial rotational viscometer. Although not widely used by the drilling industry, the Brookfield Viscometer, when run at 0.5 rpm, is useful for measuring viscosities at very low shear rates such as experienced by particles in the drilling fluid solely under the influence of gravity. Emulsion Stability– The relative emulsion stability(ES) of an invert drilling fluid is typically measured by an Electrical Stability Meter and is described in the API

Recommended Practice for Field Testing Oil-based Drilling Fluids, API RP 13B-2. The electrical stability is measured by applying a steadily increasing sinusoidal alternating voltage across a pair of parallel flat plate electrodes submerged in the invert drilling fluid. The resulting current will remain very low until a threshold voltage is reached. At this voltage, conduction between the two electrodes occurs, resulting in a rapidly increase in current. When the current reaches 61 uA, the peak voltage is measured and reported as the ES for the invert drilling fluid. The composition of the invert drilling fluid controls the electrical stability in a complex manner. Many factors influence the ES of an invert fluid, such as: • Resistivity of the continuous phase

• Conductivity of the dispersed phase (typically a brine)

• Oil to water ratio (OWR) of the invert fluid

• Temperature

• Emulsifier types

• Properties of suspended solids

• Shear history of the fluid Interpreting the oil-wet status of an invert fluid from a single ES reading is not necessarily representative of the invert fluid. All ES readings contained herein are an average of three readings. HPHT Fluid Loss --HPHT Fluid Loss is evaluated by pouring the invert drilling fluid into a HPHT filter press cell, heating the cell to desired test temperature, pressurizing the cell to the desired differential pressure, then measuring the fluid loss (in milliliters) through API standard filter paper over a period of 30 minutes. Filter cake thickness and consistency are also noted as well as the absence, or presence, of water in the filtrate. Water in the filtrate indicates emulsion instability. The filter press simulates filtration against a permeable formation at high pressures and temperatures. All examples contained herein measure HPHT fluid loss through API standard filter paper at 500 psi differential pressure. The invention replaces current organic fluid loss additives, Gilsonite and amine treated lignites (ATL) that are used in HPHT invert drilling fluids today. These products are very sensitive to bottom hole temperatures and base oil composition. Both Gilsonite and ATL are organic fine, sticky, black powders that present housekeeping issues during transport, storage, and use on the rig. The use of a Gilsonite in HPHT drilling is described in U.S. Patent 6,395,686 to Crawford. Amine treated Lignites are described in U. S. Patent 3,281,458 to Jordan. Both 6,395,686 and 3,281,458 are incorporated herein by reference. Our invention replaces these current organic fluid loss additives. Gilsonite is a naturally occurring hydrocarbon resin that forms by the action of heat and pressure on petroleum reservoirs over geologic time. The major domestic source of Gilsonite is the Unita basin in Northeastern Utah. Gilsonite is mined from underground shafts that follow the Gilsonite veins. Underground mining is expensive and carries associated safety risks. Since the Gilsonite is a naturally produced hydrocarbon resin, its’ composition varies as a function of the original composition of the petroleum and the heat and pressure that was applied over geologic time. The

Gilsonite varies in molecular weight and nitrogen content. This variability is expressed as differences in thermal softening point and as differences in solubility in various solvents. Gilsonite is graded by its’ softening point and, in a powdered form, is sold as a HPHT fluid loss additive. Gilsonite HPHT fluid loss control is accomplished via controlled solubility. Gilsonite is selected that has a softening point close to the bottom hole temperature of the borehole. At that temperature the Gilsonite softens but does not go completely into solution. This allows very tacky“blobs” of hydrocarbon resin to “plaster” the walls of the borehole. Gilsonite shown below fused ring structure renders Gilsonite hydrophobic. GILSONITE TYPICAL STRUCTURE

This concept can be a successful approach to HPHT fluid loss control if Gilsonite can be consistently selected that has the optimum softening point that matches both the bottom hole temperature and the solvency of the base oil that comprises the continuous phase of the invert fluid. A practical drawback to the use of Gilsonite results from the solubility of the bulky Gilsonite molecules in the base fluid. This solubility increases the viscosity of the base fluid across all shear rates resulting in higher Plastic Viscosity. Note that the Gilsonite does not modify low shear rheology, it simply raises viscosity across all shear rates– a definite negative. Invert drilling fluids are water in oil emulsions. In the US onshore, diesel is the typical base oil. Diesel varies widely depending upon the crude source, the source refinery, seasonal demands, and (more recently) the addition of biodiesel components– typically vegetable oils. These factors make diesel highly variable in its’ solvency.

Some locales require the use of less toxic base oils. Mineral oil is the onshore low toxicity fluid of choice. Mineral oils are more highly refined with very low sulfur and aromatic content. Mineral oils are highly paraffinic with lower solvency than highly variable diesel. Offshore drilling requires the use of biodegradable synthetic base oils (typically olefins, or esters) that allow the drill cuttings to be discarded onsite. These synthetic fluids have very consistent solvency, but different solvency than either mineral oil, or highly variable diesel. In addition to the variable solvency of base oils, and changes in the bottom hole temperature as drilling progresses, the mud engineer may be adjusting emulsifiers, wetting agents, and other factors“on the fly” that can change the solvency of the continuous phase. This variability results in the use of Gilsonite being a“hit or miss” proposition. Amine treated lignites (ATL) are produced by solubilizing humic acid contained in lignite with a small addition of NaOH, then partially, or fully, neutralizing the acid functionality with a fatty and/or aromatic amine. The structure of humic acid shown above contains fused rings that are hydrophobic and very similar to the Gilsonite structure. The amine neutralization renders the humic acid more hydrophobic and helps “mobilize” the humic acid in the continuous phase of the drilling fluid. The HPHT fluid loss reduction mechanism is thought to be like that of Gilsonite mobilized, bulky, hydrophobic amine modified humic acid“plastering” the walls of the borehole. A secondary and perhaps contributory function of the ATL is HPHT emulsion stabilization. The lignites are Leonardite Shales that domestically occur in the Black Hills area of North Dakota and in various spots worldwide including Turkey, Canada, and India. Leonardite. Shale is a near surface, oxidized bituminous mineral which is a prime source of fulvic and humic acids. Fulvic acid is the lower molecular weight, water soluble acid fraction. Humic acid is the higher molecular weight, hydrophobic fraction. Much like Gilsonite, there is no one precise chemical structure for either fluvic, or humic acids. Fulvic acid is generally recognized to have a molecular weight (MW) of 100– 100,000 and has a cation exchange capacity (CEC) of 900– 1400 meq/100g. Humic acid is generally recognized as having MW of 50,000– 500,000 and CEC of 400– 870 meq/100g. The quaternary ammonium humate fraction of the ATL is thought to be the active species for fluid loss control. Leonardite Shale is a natural mineral and varies in total organic acid content and fluvic acid/humic acid ratio. This variability is a primary source of batch-to-batch performance variation of any given commercial ATL product. There is a need in the market for an inorganic fluid loss control additive that performs equivalent or better than the current ATL or Gilsonite based additives. There is also a need in the market to have improved housekeeping around wellsite by having a lighter color additive. There is a need to have improved additives which contribute less to dust explosion hazards at the well work sites. Our invention tailors Palygorskite/Sepiolite clays for these functions and attributes. Full description of Palygorskite /Sepiolite clays is presented in Properties and Applications of Palygorskite-Sepiolite clays by E. Galan, Clay Minerals (1996) 31, 443- 453 and the entire article is incorporated herein by reference. Palygorskite/Sepiolite clays are long lathy magnesium silicate clay minerals. Palygorskite and Sepiolite clays have elements that are tubular Attapulgite clays are mined in the Northern Florida/Southern Georgia area near Tallahassee, FL.

Attapulgite clays are more needle- like, while Sepiolite clays are more ribbon-like. Attapulgites are used in various industrial applications including: pet litter, absorbents, carriers, and thickeners. Cross Section View of Palygorskite/Sepiolite

ATTAPULGITE

Attapulgite is used in salt water drilling muds as a thickener and suspension aid and is referred to as“Salt Gel”. Sepiolite is also American Petroleum Institute (API) approved as Salt Gel. 90% of the world’s Sepiolite requirement is mined in Spain by TOLSA, serving most of the same markets as Attapulgite. Sepiolite is also mined in Turkey, China, and Nevada, USA. IMV Nevada (Lhoist) mines and processes Sepiolite clay in the Amargosa Valley, NV. IMV supplies a flash dried, hammer milled Sepiolite“Salt Gel” product to the drilling industry under the tradename, SEA MUD, and under various proprietary labels. Salt Gel, whether Attapulgite or Sepiolite based, is used to gel aqueous drilling fluids with high electrolyte content. Typically, Bentonite is used in aqueous fluids, but high electrolyte content flocculates Bentonite. Salt Gel is also used in geothermal drilling as it has higher heat tolerance than Bentonite. Salt Gel has a major weakness as it provides very little fluid loss control in aqueous fluids. Thus, the HPHT fluid loss properties of the Invention are novel and totally unexpected. Both Attapulgite and Sepiolite are also used as base clays for organoclay rheological modifiers for invert emulsion fluids. These rheological modifiers improve the low shear rheology of invert drilling fluids while having little, if any, effect upon apparent viscosity. BENTONE 990 (Elementis) and RM 99 (RheoMinerals) are two such rheological modifiers. These rheological modifiers have gained popularity as directional deviated drilling is now standard practice for drilling oil/gas shale formations. These rheological modifiers are typically 70% - 90% Palygorskite/Sepiolite clay and 10% - 30% fatty quaternary amine (QUAT). The most typical fatty quaternary amine treatment is dimethyl dihydrogenated tallow ammonium chloride (DMDHT) sold under the

tradenames Arquad 2HT (Akzo) and Adogen 442 (Evonik).

These rheological modifiers have not been marketed as fluid loss control additives, nor has fluid loss control been mentioned as an attribute of these modifiers. BRIEF SUMMARY OF INVENTION A Palygorskite/Sepiolite organo-clay additive and its use to reduce the HPHT Fluid Loss in an invert emulsion drilling fluid. Discovery of the ranges of degree of substitution by the incorporation of organic species into the clay and the extent of mechanical exfoliation of the fabric of

Palygorskite/Sepiolite clays resulting from its mechanical processing. The resulting tailored organoclay from the Palygorskite/Sepiolite mineral clay determines the balance between HPHT Fluid Loss improvement and rheology improvement. The modification process to make this additive is yet another aspect of this invention. A yet another aspect is a process to incorporate this additive directly into the drilling fluid composition by in-situ modification of the clay. A yet another aspect of the invention is to provide an invert emulsion drilling fluid that is less sensitive to bottom hole temperatures. A yet another aspect of the invention is to provide HPHT Fluid Loss properties to a drilling fluid which are less sensitive to the base oil selection. A yet another aspect of the invention is to allow the drilling fluid composition to form thinner and more cohesive filter cakes. A yet another aspect of the invention is that this fluid loss additive is less susceptible to flash dust explosion than the finely powdered Gilsonite and ATL due to its lower organic content. A yet another aspect of the invention is to enable good housekeeping during transport, storage and use on the rig by having HPHT Fluid Loss modification additives of lighter color than the existing dark brown to black Gilsonite and ATL fluid loss control additives. See Figure 7 for color characterization of fluid loss additive, where our inventive additive is light colored vs the black color of competitive Gilsonite and ATL additives. A yet another aspect of the invention is to further improve the rheological profile of the drilling fluid by increasing the low shear rate viscosity of the fluid with minimal impact upon the high shear viscosity.

BRIEF DESCRIPTION OF DRAWINGS Figure 1 Micrograph of AVS (Amaragosa Valley Sepiolite) made by INV. Not

Extruded. Lab Milled with heavily densely matted, few individual laths visible. Figure 2 Micrograph of Spanish Sepiolite made by TOLSA, Spain. Not Extruded,

Lab Milled with lighter matting density, some breakages of laths, longer and more individual laths. Figure 3 Micrograph of AVS. Extruded, Solar Dried, Roll Milled to 94% minus 200 mesh with extrusion disrupted matted structure and with breakages of laths evident.

Figure 4 Micrograph of AVS. Extruded, Flash Dried, Hammer Milled to 82% minus

60 mesh with disrupted matting (not as much as solar dried and roller milled sample) and with much reduced lengthwise breakage (compared to roller milled).

Figure 5 Micrograph of Florida Attapulgite which has been extruded, flash dried, hammer milled showing reduced matting than AVS but more than Spanish Sepiolite. Figure 6 Micrograph of Spanish Sepiolite (Pangel S-9 by TOLSA) wet processed, water washed and wherein the wet processing has delaminated a large portion of the matted lathes resulting in very high viscosity in water but a poor base clay for our invention. Figure 7 Picture showing physical forms of our invention , Gilsonite and ATL

DETAILED DESCRIPTION OF INVENTION Unexpectedly, RheoMinerals has discovered that Palygorskite/Sepiolite clays can reduce HPHT fluid loss in invert emulsion drilling fluids. This finding is directly opposed to the well-known fluid loss control deficiency of Palygorskite/Sepiolite clays in aqueous drilling fluids. Furthermore, RMI has discovered that various

Palygorskite/Sepiolite clays are not equal in their ability to reduce HPHT fluid loss. Sepiolite clay is more effective than Attapulgite clay and a specific Sepiolite source is more effective than other Sepiolite clays. This is believed to be due to the original mineral clay structural differences between various Sepiolites and Palygorskites. The Palygorskite/Sepiolite clay must be rendered organophilic in order not to negatively affect the stability of the water in oil emulsion. Untreated gelling clays are notorious for decreasing the emulsion stability (ES) of an invert emulsion drilling fluid. Palygorskite/ Sepiolite clays have medium cation exchange capacity of 30-40 Meq/100 grams. And a very high surface area of 150-350 m²/g. The desired

hydrophobic/organophilic character may be imparted to the clay by: • Surface pre-treatment of the Palygorskite/Sepiolite clay mineral with a suitable QUAT, silane, titanate, or other surface-active agents.

OR

• Addition of the Palygorskite/Sepiolite clay mineral to the invert emulsion drilling fluid and in-situ addition of emulsifier, wetting agent, dispersant, or other-surface active agents in amounts sufficient to render the Palygorskite/Sepiolite clay mineral sufficiently hydrophobic/organophilic. The preferred embodiments of the Invention utilize Sepiolite clay mined by IMV Nevada in Amargosa Valley, NV and pre-treated with a surface-active agent thereby rendering the Sepiolite clay sufficiently hydrophobic/organophilic to provide ES stability. More specifically, the Amargosa Valley Sepiolite (AVS) is pre-treated with the commonly used DMDHT (dimethyl dehydrogenated tallow ammonium chloride) at a relatively low concentration (10%, by weight, or less), the minimal treatment level required to render the Sepiolite sufficiently hydrophobic/organophilic, or pre-treated with PTEO

(phenyltriethoxysilane), or PTMO (phenyltrimethoxysilane) at relatively low

concentration (5%, by weight, or less). PTMO/PTEO

PTEO/PTMO are common surface treatments for mineral products that impart hydrophobicity and feature thermal stability. Mineral treatment levels with PTEO/PTMO are typically 1– 2% by weight. The silanes form covalent siloxane bonds with silanol groups on mineral surfaces by condensation and evolving alcohol. The cationic QUATS form ionic bonds to cation exchange sites on the clay surface neutralizing naturally occurring negative charge. When pretreated with QUATS, the AVS version of the Invention retain some activity as a low shear rheological modifier, improving the low shear rheology of the invert emulsion while having minimal effect on the higher shear rate rheology. When pretreated with silane, the AVS version of the Invention has minimal rheological function. The proposed mechanism for the invention’s HPHT fluid loss reduction is via the formation of a“papier Mache” coating of the borehole wall by the Palygorskite/Sepiolite lathes. Sepiolite is more ribbon-like than Attapulgite and is more effective at coating the borehole walls. There is an inverse relationship between various Sepiolite sources regarding rheological properties and HPHT fluid loss control. The more well-formed, distinct Sepiolite“ribbons” (such as that mined by TOLSA in Spain) typically yield higher untreated viscosities in fresh water and salt water dispersions than the less well formed, matted AVS. Conversely, the matted together AVS ribbons are more effectively coat the borehole wall and reducing HPHT fluid loss. These differences can easily be seen in the SEM photos at 80,000x magnification. Figures 1-6 show the clay with matted structures and the corresponding breakdown with shear and water processing. Sepiolite producers typically go to great lengths to break down the agglomerated Sepiolite ribbons into individual ribbons to enhance rheological properties. This is usually accomplished by applying laminar shearing (such as extrusion) to a thick aqueous Sepiolite paste. The extruder delaminates bundles of elongated particles which improve the viscosity properties. The present invention does not require this delamination as the agglomeration (matting) present in the Amargosa Valley Sepiolite does not negatively affect HPHT fluid loss control and, it is conjectured, improves the fluid loss control. The extent of this delamination during processing will determine the degree of matting that is retained and the fluid loss control properties and will be inversely related to resulting rheological properties. We introduce the term“minimally processed” to describe the special processing (or lack thereof) required to make Sepiolite and Palygorskite suitable for our inventive formulation. This minimal processing is quite different from the way these clays are produced for the current commercial markets. Today's high shear processing makes the clay unsuitable for use as a Fluid Loss Control Additive. Delamination of laths via extensive shear processing and the resulting destruction of the matting decreases HPHT Fluid Loss control properties by allowing transfer of the invert drilling fluid across the filter cake. A borehole wall with such a structure coated on it will not minimize drilling fluid loss. Conversely minimal shear processing that preserves this matted structure is mandatory in this invention. Minimal processing is processing that does not irreversibly destroy the matted agglomerated morphology of the clay ribbons. Our fluid

loss control is a result of matted morphology present in the Armargosa Valley, NV Sepiolite and, to a lesser extent, present in other Sepiolite and Palygorskite and the use of minimal processing during the manufacture of the Invention. Since such deagglomeration occurs with high shear processing, minimal processing means no high shear processing of clays with high shear processes such as extrusion, milling, etc. Minimally processed also means no intensive shearing of hydrated clays, or no intensive mixing of any type. The test for what is included in minimal processing is processing that substantially preserves the agglomerated matted structure of the clay ribbons. If the processing does not preserve this matted structure, then the clay has not been minimally processed.

We have not yet quantitatively determined the threshold shear rate and exposure time needed to result in unacceptable destruction of the matted morphology. However, we have made our inventive discovery with certain types of processing (shear rate and time profiles) that can be classified as "minimally processed" to provide instances of our discovery. It is to be noted, without limiting any of the scope of the acceptable processing covered in this invention, that a wide range of shear with the myriads of processes and machines are possible. We have qualified only a few distinctive cases of special processing but that the entire genus of minimal processing (as characterized by shear rate and exposure time variables) is intended to be covered by this invention.

It should be noted that although shearing during the manufacturing process is highly detrimental to the HPHT Fluid Loss control properties of the Invention, shearing of an invert fluid containing the Invention, such as that encountered during the circulation of the fluid, has no measurable effect on the HPHT Fluid Loss properties of the Invention.

Additionally, besides shear-based delamination described above, hydration with large amounts of water also tends to destroy these agglomerated matted structures in Sepiolite. Wet processing, as illustrated by the SEM image of wet processed Spanish Sepiolite, results in delamination of the matted structure and is highly undesirable for our invention. The final water content of the Invention should be around 5%, or less. Drying temperatures should be less than 150 degrees C.

Several Invert Emulsion Drilling Fluids were compounded and tested for their performance attributes as described in examples below using a standard recipe for a 14 ppg 80:20 OWR Mineral Oil Drilling Fluid shown below. The following summary shows the Examples prepared and tested.

The standard recipe for drilling fluid described below was used in the making of the compounded invert emulsion drilling fluid for subsequent Fluid Loss Control additive evaluation testing.

Subsequent standard performance testing of the compounded drilling fluid was as follows.

Our inventive fluid loss additive is obtained by treating a specially processed Sepiolite clay with a surface-active agent. The special processing calls for clay manufacturers to bypass certain processing steps in their traditional routine

manufacturing operations. The additive is then used in a drilling fluid formulation shown above, Alternatively, the specially processed clay may be treated to form an additive in- situ while formulating the drilling fluid itself. There are two mixers used in the compounding of the Drilling Fluid. The

Multimixer (malt mixer) and a Rio Blender (bar blender). The multimixer is a low shear mixer, the Rio is a high shear mixer. The fluid is aged overnight in a Roller Oven that provides minimal shearing.15 minutes on the Rio Blender would be equivalent to many complete circulations of the mud. An hour on the Rio would be equivalent to many days circulation. The Rio shearing so intense that 15 minutes will increase the temperature of the fluid form 70 F to 160-170 F.

Example 1: Surface treatments of PTEO and PTMO applied to minimally processed AVS in 14 lbs./gal.80:20 OWR Mineral Oil Fluid are compared in performance. Non-extruded, coarsely ground AVS was treated with PTEO at 1-2% and 1.5-2% PTMO on a dry weight basis by simple mixing in a KitchenAid™ Professional 550HD Stand Mixer equipped with a KitchenAid Heated Mixing Bowl. The PTEO was first diluted to 10% active in Isopropanol 91% (IPA91) to aid in uniform application of the silane. The Heated Mixing Bowl was set at 210F and the clay/PTEO mixture was mixed for 15 minutes. The mixture was then dried in a lab oven set at 210F until the volatile content (water & IPA) was less than 5%. The dried mixture was then ground once through an IKA laboratory hammer mill and the milled product was screened to minus 60 mesh. Similar processing with PTMO version. The treated clay was then compounded as an HPHT Fluid Loss additive and evaluated along with two commercially available ATLs (VC2 and CA9) and vs. a“premium” Gilsonite (CHT) in a 14 ppg, 80:20 OWR Mineral Oil.

Example 2: Surface treatments of 2M2HT (4%- 10%), 10% 3MHT and 10% MB2HT applied to minimally processed AVS and then compounded in 14 lbs./gal.80:20 OWR Mineral Oil Fluid. Non-extruded, coarsely ground AVS was treated with 2M2HT at a 92:8 dry, active weight ratio by mixing in a KitchenAid™ Professional 550HD Stand Mixer equipped with a KitchenAid Heated Mixing Bowl. The 2M2HT was melted at 180F. The 2M2HT is supplied at 82% active diluted with ethanol(EtOH) and water. The Heated Mixing Bowl was set at 210F and the molten 2M2HT was slowly added to the AVS in the mixing bowl while mixing. Mixture was mixed for 15 minutes. The mixture was then dried in a lab oven set at 210F until the volatile content (water & EtOH) was less than 5%. The dried product was then milled once through the IKA lab hammer mill screened to minus 60 mesh. Similar processing for other treatments too.

Example 3: Differently processed AVS clay were treated with 1.5% PTEO and compounded in 14 lbs./gal.80:20 OWR Mineral Oil Fluid. Two batches (A and B) of the PTEO version of the Invention were produced based upon AVS that was further processed by IMV Nevada. Batch A was based upon an extruded, flash dried and hammermilled AVS with relatively coarse particle size (up to 18% greater than 60 mesh). Batch B was based upon an extruded, flash-dried and roller milled AVS with much finer particle size (94% less than 325 mesh). Both Batch A & B were treated as outlined in Example 1.

The extrusion process exfoliates the individual Sepiolite ribbons. The flash-drying hammermill literally“explodes” the Sepiolite bundles by instantaneously vaporizing unbound water in the clay while simultaneously striking the Sepiolite particles with high kinetic energy. The Roller Mill grinds dry (approx.10% moisture) extruded Sepiolite clay in a manner like the action of a mortar & pestle. The Roller Mill tends to break the individual Sepiolite ribbons lengthwise.

Example 4: Clays from TOLSA and Florida were treated with 1.5% PTEO and compounded in 14 lbs./gal.80:20 OWR Mineral Oil Fluid. The clays were minimally processed Spanish Sepiolite (TOLSA) and extruded, flash dried, hammermilled Florida Attapulgite (made by Active Minerals Inc.). These clays were compounded using standard compounding recipe after pretreatment with PTEO. Following test results were obtained on the compounded drilling fluid.

Example 5: Effect of higher temperature 375F in the 16-hour long hot rolling step in the invert mud test procedure (as opposed to the standard temperature of 350F) of minimally processed AVS treated with PTMO and 2M2HT using 14 lbs./gal.80:20 OWR Mineral Oil Fluid

Example 6: The base oil of the invert emulsion was switched from Mineral Oil to Diesel per recipe and processing below. Fluid Loss Control Additives with minimally processed AVS with 10% 2M2HT and 1.5% PTMO treatments were made. Performance attributes were tested.

Example 7: An in-situ version of the inventive additive was produced by addition of AVS to the 14 ppg 80:20 OWR Diesel oil phase along with 1.5%PTEO. The drilling fluid recipe and processing is shown below.

Performance attributes were tested.

Our invention can also be covered by a product by process claim. The product clay is specially formed with special processing method that limits the deterioration of the matted structure of the clay and therefor preserves its Fluid Loss performance. The criticality lies in the special processing needed for the performance.

Claims

CLAIMS We claim: 1. A fluid loss additive for HPHT invert emulsion drilling fluid comprising a minimally processed Palygorskite and/or Sepiolite clay.

2. The fluid loss additive of claim 1 wherein the minimally processed clay has a

substantial matted morphology comprising of matted laths, ribbons, and rods.

3. A fluid loss additive of claim 2 wherein the clay has not been extruded, hammer or roller milled or hydrated.

4. A fluid loss additive of claim 2 wherein the minimally processed clay has been treated with a surface - active agent from the group consisting of silanes, QUATs, titanates or mixtures thereof.

5. The fluid loss additive of Claim 1 wherein the said clay is a matted Sepiolite

preferably from Amargosa Valley, NV.

6. A process of forming a HPHT fluid loss control additive of Claim 4 comprising (i) selecting Palygorskite or Sepiolite clay that has been minimally processed, (ii) treating the selected clay with a surface - active agent from the group consisting of silanes, QUATs, titanates or mixtures thereof

(ii) coarsely grinding the treated clay to yield a fluid loss control additive.

7. An invert emulsion drilling fluid composition compounded with the fluid loss

additive of claim 1.

8. A method of improving the HPHT fluid loss performance of an invert emulsion drilling fluid composition comprising adding to said fluid a HPHT fluid loss control additive of Claim 1.

9. A process of improving the HPHT Fluid Loss performance of an invert emulsion drilling fluid composition comprising

(i) adding in-situ minimally processed Palygorskite or Sepiolite clays to the oil phase of the invert emulsion during the making of the emulsion, and (ii) further adding in-situ surface active agents comprising from the group of silanes, QUATs, titanates or mixtures.