Patent Application
20140155302
The present invention relates to oil well drilling fluid compositions, oil well cement compositions and slurry of weighting material for use in oil well drilling, fluids and oil well cement composition.
In the exploration for oil and gas both drilling fluids and cement slurries must have the right density to counterbalance the downhole pressure in the formations. Drilling fluids are generally used to serve certain functions such as lifting the cuttings to the earth's surface, lubricating, and cooling the drill bit, maintaining the downhole pressure, etc. . . . There are two major classes of drilling fluids, namely water based (WBM) and non-aqueous based drilling fluids (NAF). Normally water based drilling fluid comprises water as continuous phase together with other additives such as, a viscosity modifier such as clay or organic polymer, shale inhibitor, dispersant and a weighting agent such as brine, or any heavy weight particles with a specific gravity (SG)>2 g/cm3.
One of the main functions of oil well cement compositions is to maintain the well integrity during the well's lifetime which can be more than 30 years. The cement contributes to reduce the risk of uncontrolled flow of oil or gas (provide permeable-zones isolation), provide mechanical support for the casing string, protect casing from corrosion, and support the wellbore walls to prevent collapse of formations. Oil well cements are further used to make permanent or temporary seals (plugs).
Cement slurry comprises mainly Portland cement, water and additives such as dispersant, fluid loss, reducing agents, retarder and others. It may further contain rubbery material or fibers to improve the mechanical properties, and hollow spheres or weighting agents for density optimization.
The commonly used weighting agents for both drilling fluids and cement slurries are barite (BaSO4, SG minimum 4.2), manganese tetraoxide (Mn3O4, SG 4.7-4.9), calcium carbonate (CaCO3, SG 2.7-2.8), ilmenite (FeTiO3, SG 4.5-4.7), hematite (Fe3O4, SG 4.9-5.2), galena (PbS, SG 7.4-7.7) and grinded silica (SiO2, SG 2.2-2.3).
ilmenite, iron titanium oxide (FeTiO3), as a mined mineral was first introduced to oil & gas exploration and production as weighing agent by Titania AS in 1979.
In the paper “Application of ilmenite as weight material in water based and oil based drilling fluids” (SPE 71401) by A. Saasen et al., published for the 2001 SPE Annual Technical Conference and Exhibition in New Orleans 30 September—3 Oct. 2001. The use of ilmenite in water based and oil based drilling fluids is described. The ilmenite used has a D50 of 9.5 μm+/−1.5 μm, with fraction of particles above 45 μm less than 1.5% by weight and fraction of particles below 1 μm less than 10% by weight. The particle size distribution is measured by the sedimentation method using Sedigraph. This gives particle distribution in % by weight. Full scale tests with drilling mud containing ilmenite and barite as weighting agents showed that use of ilmenite instead of barite did not imply increased abrasion. It has however been found that the rheological properties are not satisfactory when using ilmenite with the particle size described by Saasen et al.
In US patent application No. US 2005/0277551 it is disclosed a system for increasing the density of a fluid phase of a drilling fluid by adding a solid phase weighting material having a particle size distribution of at least 50% by weight particles in the range of about 1 μm to about 5 μm and at a least 90% by weight particles in the range of 4 μm to 8 μm. The solid phase material is selected from the group consisting of barite, calcite, hematite, ilmenite or combinations thereof. However all examples are with barite and there is no indication of results obtained by using other weighting material than barite.
According to a first aspect the present invention relates to oil well drilling fluids wherein the oil well drilling fluid comprises a weighting agent consisting of microfine, particulate ilmenite having a FeTiO3 content of at least 85% by weight, a specific surface area (BET) between 1 and 5 m2/g, where 90% by volume of the particles have a size of less than 12.5 μm and a D50 between 3 μm and 6 μm by volume measured by laser diffraction using Malvern laser diffraction particle size analyzer, where the particles have a median high sensitivity circularity (HSCirc.[n,0.5]) of at least 0.85 determined by image analysis using Morphologi®G3 particle characterization system from Malvern® Instruments. The median high sensitivity circularity (HSCirc.[n,0.5]) will hereafter be referred to as average circularity.
Preferably the specific surface of the ilmenite is between 1.5 and 4 m2/g.
The average circularity of the microfine ilmenite particles is preferably at least 0.90.
The circularity as a parameter that describes the particle morphology or shape is determined by the following equation;
High Sensitivity (HS) Circularity=4πA/P2
where A is the particle area and P is its perimeter.
The average circularity of particle can be within the range 0-1, where a perfect circle has circularity of 1 while a very irregular object has circularity closer to 0. Weighting agents with high circularity are desirable for oil well drilling fluids and oil well cement slurries as it enhances the flow properties by means of low rheology and less abrasiveness compared to materials having a similar size but with lower average circularity.
The ilmenite particles used in the present invention is produced by crushing and milling ilmenite mineral having a low content of magnetite and subjecting the milled ilmenite particles to a sedimentation and flotation process in order to remove foreign mineral particles associated with the ilmenite. After drying the ilmenite particles are subjected to further milling and are sieved and classified to obtain the desired particle size distribution and specific surface area.
The particle size of the ilmenite used in the present invention is substantially smaller than the particle size used in Saasen et al. Particle size measurement by laser diffraction using Malvern on the ilmenite used by Saasen et al. showed a D50 of 18 μm.
It has been found that the oil well drilling fluids according to the present invention show very good properties compared to drilling fluids containing coarser ilmenite according to Saasen et al. and according to the use of barite as weighting agents. Thus the sag is substantially improved compared to drilling fluids containing barite and more coarser ilmenite. Also the plastic viscosity is improved. Ilmenite is an acid soluble mineral. It dissolves in mineral acids such as HCl, H2SO4 and H3PO4 and by many organic acids. With the small particle size acid solubility for ilmenite used as weighting material according to the present invention is good. The acid solubility of weighting agents is of great technical importance for drilling fluids, as the mud filter cake formed during the drilling has to be removed before starting producing oil. This is done in a step called well completion. Barite on the other hand is not soluble in acids and is thus difficult to remove from the well. Normally expensive chelating agents like EDTA are used to improve the solubility of barite.
Another advantage of the oil well drilling fluids of the present invention is that ilmenite particles have a good mechanical strength. Thus impact from the drilling bit will not break the ilmenite particles into smaller particles. This is important due to the fact that if the particle size of a drilling fluid changes during the drilling the rheological properties will also change. Barite on the other hand has a low strength and will be broken down to smaller particles during the drilling operation resulting in changing the viscosity of the drilling fluid.
According to another aspect the present invention relates to a high density oil well cement slurry comprising water, Portland cement, silica flour, microsilica, a weighting material and optionally a fluid loss additive and a retarder, wherein the weighting material is particulate microfine ilmenite having a FeTiO3 content of at least 85% by weight, a specific surface area (BET) between 1 and 5 m2/g, and where 90% by volume of the particles have a size of less than 12.5 μm and a D50 between 3 μm and 6 μm measured by laser diffraction using Malvern laser diffraction particle size analyzer, and where the particles have an average circularity of at least 0.85 determined by image analysis.
Preferably the average circularity of the microfine ilmenite particles is at least 0.90.
It has been found that the high density oil well cement slurry according to the present invention containing microfine ilmenite has a low tendency of settling compare to oil well cement slurries using hematite as weighting to the present invention shows improved rheological properties compared to oil well cement therein containing hematite.
The microfine ilmenite used in the oil well drilling fluids and in the oil well cement composition according to the present invention can be added in dry particulate form. For aqueous based drilling fluids and cement composition the microfine ilmenite can also be added in the form of an aqueous slurry.
The present invention therefore also relates to a stable non settling aqueous slurry comprising water, up to 85% by weight microfine ilmenite having a FeTiO3 content of a least at 85% by weight, a specific area (BET) between 1 and 5 m2/g, where 90% by volume of the particles have a size of less than 12.5 μm and a D50 between 3 and 6 μm by volume measured by laser diffraction using Malvern laser diffraction particle analyzer, where the particles have an average circularity of at least 0.85 determined by image analysis and 0.05 to 1% dispersant based on the weight of dry microfine ilmenite selected from an ethoxylated polycarboxylate, polyacrylic aid salt, alkali metal salt of lignosulphonate and biopolymer sulphonated acrylite copolymer and the dispersant having an molecular weight below 50 000 g/mol.
Preferably the microfine ilmenite particles have an average circularity of at least 0.90.
Preferably the dispersant has a molecular weight between 3000 and 20 000 g/mol.
It has been found that the slurry of microfine ilmenite according to the invention is very stable and shows very little settling.
Oil based drilling fluids with a specific gravity of 2.1 g/ml having the compositions shown in Table 1 were prepared and tested according to the API 13B standard. The drilling fluids in Table 1 were made using the following weighting materials:
The properties of the tested drilling fluids are shown in Table 2. The drilling fluids were tested before hot aging (BHR) and after hot aging (AHR).
It can be seen from Table 2 that even the specific surface area for microfine ilmenite according to the present invention is much higher than for barite, the plastic viscosity (PV) was considerably lower for the oil drilling fluid according to the invention than for the drilling fluid. Also the sag factor was much lower for the drilling fluid containing microfine ilmenite than for the drilling fluid containing barite.
It can further be seen from Table 2 that the microfine ilmenite according to the present invention provides a more stable drilling fluid with a considerably lower sag factor than the drilling fluid containing the more coarse ilmenite with a D50 of 18 μm. The supernatant liquid was lower for the microfine ilmenite according to the invention.
The fluid loss after hot aging of the drilling fluid containing microfine ilmenite according to the invention of 8.8 ml is relatively higher than the desired value of <5 ml. This can be further reduced by increasing the content of the fluid loss agent.
Water based drilling fluids with a specific gravity of 2.3 g/ml having the composition shown in Table 3 were prepared and tested according to API 13B standard. The drilling fluids in Table 3 were made using microfine ilmenite according to the present invention having a D50 of 5 μm measured by laser diffraction using Malvern laser diffraction particle size analyzer and standard API barite as weighting materials. The fluids were mixed using a high shear mixer. The acrylate dispersant is an aqueous solution with an active substance of 40% by weight.
The compositions were subjected to hot aging for 16 hours at 80° C. The rheology was measured using Fann viscometer model 35 at 50° C. and static sag was measured. High pressure high temperature (HPHT) filtration was conducted at 80° C. with a differential pressure of 500 PSI.
As shown is Table 4 the drilling fluid with ilmenite according to the invention showed a lower plastic viscosity than the drilling fluid containing barite. The rheology of the fluids is reduced slightly after hot aging due to thermal and shear degradation. The fluid loss measured at 80° C. for the two drilling fluids is within acceptable range (<15 ml). The drilling fluid containing microfine ilmenite according to the present invention showed much lower sag factor than the drilling fluid containing barite.
Water based drilling fluid with a specific gravity of 2.1 g/ml suitable for high temperature (>150° C.) application having a composition as shown in Table 5 were prepared and tested according to API 13B standard. The drilling fluids in Table 5 were made using ilmenite according to the invention and ilmenite according to Saasen et al. having a D50 of 18 μm measured by laser diffraction using Malvern laser diffraction particle size analyzer as weighting materials.
The properties of the drilling fluids were measured before and after static hot aging for 16 hours at 150° C. The results are shown in Table 6.
The results in Table 6 further show that ilmenite according to the invention even though it has three times smaller particle size than the ilmenite of 18 μm shows quite similar rheology. Generally one would expect that the rheology to increase as the size of the particles decreases, but this is not the case here. This behaviour can be related to the high circularity of the ilmenite particles according to the present invention. The sedimentation was greatly improved for the drilling fluid according to the invention as shown by the sag factor and the supernatant liquid. The low supernatant value reflects a high stability of the drilling fluid.
In order to test the acid solubility of the microfine ilmenite according to the present invention a set-up as shown in
To demonstrate the effect of ilmenite size on the dissolution rate three different grades ilmenite with an average size (D50) of 5, 18 and 70 μm were tested. The solubility of ilmenite was tested at 100° C. in two media with different HCl concentrations by means of 10 and 20 wt % by the weight of solution, respectively. In the 20 wt % solution additional 0.5 mol methanol was added to enhance the solubility as reported in literature.
Solution I (10% HCl i.e. 2.83 mol/l)
40.5 g conc HCl (37%)+109.5 g water+7.5 g ilmenite
Solution II (20% HCl i.e. 5.9 mol/l)
81 g conc. HCl (37%)+66 g water+3 g methanol+7.5 ilmenite
The diagrams in
The powder flow of the microfine ilmenite with D50 of 3.7 μm and D50 of 5 μm and BET of 1.9 and 1.6 m2/g respectively were tested using a ring shear tester RST-XS from Dr. Dietmar Schulze Schüttgutmesstechnik, as a well known technique for powder flow characterization. For comparison purpose the powder flow of barite with D50 of 15 μm and ilmenite with D50 of 18 μm were tested. As shown in Table 7 microfine ilmenite showed good flow function coefficient (FFC) value at a consolidation pressure of 20000 Pa. The classification of flowability of powders by FFC is as follows:
FFC<1—not flowing
1<FFC<2—very cohesive
2<FFC<4—cohesive
4<FFC<10—good flowing
10<FFC —free flowing
Such FFC data suggest that ilmenite with D50 of ca. 5 μm and 3.7 μm should be easily to transport pneumatically without the need for granulating the powder.
Three oil well cement compositions were containing three different weighting materials to produce cement slurries with a specific gravity of 2.22 g/ml. The composition of the oil well cement slurries are shown in Table 8.
As shown in Table 8 the following three weighting materials were used:
The cement slurries were prepared and tested according to API 10A protocol. The following equipment was used to prepare and test the cement slurries:
The results of the tests are shown in Table 9.
As can be seen from Table 9 the cement slurry containing microfine ilmenite has a considerably lower rheology than the cement slurry containing hematite. A large settling was observed for the cement slurry containing hematite and the amount of free water was higher compare to that for the cement slurry containing ilmenite or micromax. This settling may cause inhomogeneity in the cured cement. The use of microfine ilmenite has overcome this problem. As can be seen from Table 9 the cement slurry containing microfine ilmenite did not show any free water and thus also shows a lower settling tendency than the cement slurry containing hematite.
4 slurries containing ultrafine ilmenite according to the invention. The slurries contained about 80% by weight of ultrafine ilmenite and different dirspersant. The composition and the pH and the viscosity of the slurries are shown in Table 10.
As can be seen from table 10 the viscosity of the slurries is good and within the pumpable range.
| Number | Date | Country | Kind |
|---|---|---|---|
| 20111012 | Jul 2011 | NO | national |
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/NO11/00327 | 11/21/2011 | WO | 00 | 11/1/2012 |
