WO2014035499A1 - An invert emulsion transition fluid containing calcium aluminate cement - Google Patents
An invert emulsion transition fluid containing calcium aluminate cement Download PDFInfo
- Publication number
- WO2014035499A1 WO2014035499A1 PCT/US2013/042395 US2013042395W WO2014035499A1 WO 2014035499 A1 WO2014035499 A1 WO 2014035499A1 US 2013042395 W US2013042395 W US 2013042395W WO 2014035499 A1 WO2014035499 A1 WO 2014035499A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- fluid
- transition fluid
- transition
- cement
- introducing
- Prior art date
Links
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
-
- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B28/00—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
- C04B28/02—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing hydraulic cements other than calcium sulfates
-
- C—CHEMISTRY; METALLURGY
- C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
- C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
- C04B28/00—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
- C04B28/02—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing hydraulic cements other than calcium sulfates
- C04B28/06—Aluminous cements
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/40—Spacer compositions, e.g. compositions used to separate well-drilling from cementing masses
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/424—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells using "spacer" compositions
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02W—CLIMATE CHANGE MITIGATION TECHNOLOGIES RELATED TO WASTEWATER TREATMENT OR WASTE MANAGEMENT
- Y02W30/00—Technologies for solid waste management
- Y02W30/50—Reuse, recycling or recovery technologies
- Y02W30/91—Use of waste materials as fillers for mortars or concrete
Definitions
- An oil-based transition fluid contains a calcium aluminate cement.
- the transition fluid can be used in lieu of, or in addition to, a spacer fluid.
- the transition fluid can be introduced into the wellbore after the introduction of an oil- based drilling fluid and before the introduction of a cement composition.
- the transition fluid functions to maintain or decrease the setting time of the cement composition and can also enhance some of the properties of the cement composition, such as the compressive strength.
- a transition fluid comprises: a hydrocarbon liquid, wherein the hydrocarbon liquid is the external phase of the transition fluid; an aqueous liquid, wherein the aqueous liquid is the internal phase of the transition fluid and wherein the aqueous liquid comprises a water-soluble salt; and a calcium aluminate cement.
- a method of cementing in a subterranean formation comprises: introducing the transition fluid into the subterranean formation;
- step of introducing the cement composition is performed after the step of introducing the transition fluid and wherein the cement composition comprises cement and water.
- Fig. 1 is a graph of compressive strength in psi for several contaminated cement compositions according to an embodiment .
- Fig. 2 is a graph of compressive strength in psi for several contaminated cement compositions according to other embodiments .
- the test transition fluid consists essentially of the hydrocarbon liquid, the aqueous liquid, the calcium aluminate cement, and the surfactant.
- the fluid can contain other ingredients so long as the presence of the other ingredients does not materially affect the basic and novel characteristics of the claimed invention, i.e., so long as the test fluid has the specified plastic viscosity, etc.
- a “fluid” is a substance having a continuous phase that tends to flow and to conform to the outline of its container when the substance is tested at a temperature of 71 °F (22 °C) and a pressure of one atmosphere “atm” (0.1 megapascals "MPa”) .
- a fluid can be a liquid or gas.
- a homogenous fluid has only one phase; whereas a heterogeneous fluid has more than one distinct phase.
- a colloid is an example of a heterogeneous fluid.
- a colloid can be: a slurry, which includes an external liquid phase and undissolved solid
- an emulsion which includes an external liquid phase and at least one internal phase of
- the term “emulsion” means a colloid in which an aqueous liquid is the external phase and a hydrocarbon liquid is the internal phase.
- the term “invert emulsion” means a colloid in which a hydrocarbon liquid is the external phase and an aqueous liquid is the internal phase.
- Any of the phases of an emulsion or invert emulsion can contain dissolved
- cement composition is a mixture of at least cement and water.
- a cement composition can include additives.
- cement means an initially dry substance that develops compressive strength or sets in the presence of water.
- An example of cement is Portland cement and calcium aluminate cement (CAC) .
- CACs generally have a faster setting time compared to conventional hydraulic
- cements such as Portland cements.
- set and all grammatical variations thereof means the process of becoming hard or solid through curing.
- a cement composition is generally a slurry in which the water is the external phase of the slurry and the cement (and any other insoluble particles) is the internal phase.
- composition can include dissolved solids.
- Oil and gas hydrocarbons are naturally occurring in some subterranean formations.
- a subterranean formation containing oil or gas is sometimes referred to as a reservoir.
- a reservoir may be located under land or off shore. Reservoirs are typically located in the range of a few hundred feet
- a well can include, without limitation, an oil, gas or water producing well, an injection well, or a geothermal well.
- a "well” includes at least one wellbore.
- a wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched.
- the term "wellbore” includes any cased, and any uncased, open-hole portion of the wellbore.
- a near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore.
- a "well” also
- the near-wellbore region is generally considered to be the region within approximately 100 feet of the wellbore.
- into a well means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.
- a wellbore is formed using a drill bit.
- a drill string can be used to aid the drill bit in drilling through a subterranean formation to form the wellbore.
- the drill string can include a drilling pipe.
- a drilling fluid sometimes referred to as a drilling mud, may be circulated downwardly through the drilling pipe, and back up the annulus between the wall of the wellbore and the outside of the drilling pipe.
- the drilling fluid performs various functions, such as cooling the drill bit, maintaining the desired
- Some subterranean formations can be adversely affected by certain types of drilling fluids.
- a formation that can be adversely affected by certain types of drilling fluids is a water-sensitive formation.
- a drilling fluid is an emulsion, and the water comes in contact with a water-sensitive formation, then the water can adversely affect the subterranean formation.
- Some of the adverse effects can include swelling or sloughing of the subterranean formation, or gumbo formation.
- an invert emulsion drilling fluid can be used.
- An invert emulsion drilling fluid is commonly referred to as an oil-based drilling fluid or oil-based mud.
- oil based means a fluid having an external phase comprising a hydrocarbon liquid.
- An oil-based drilling fluid can include a synthetic hydrocarbon liquid.
- hydrocarbon liquids used in oil-based drilling fluids include, but are not limited to: a fractional distillate of crude oil; a fatty derivative of an acid, an ester, an ether, an alcohol, an amine, an amide, or an imide; a saturated hydrocarbon (such as an alkane or paraffin); an unsaturated hydrocarbon (such as an internal olefin); a branched hydrocarbon; and a cyclic hydrocarbon.
- hydrocarbon liquids include, but are not limited to: ENCORE® drilling fluid, BAROID ALKANETM base fluid, XP-07TM base fluid, and PETROFREE® ESTER base fluid, marketed by Halliburton Energy Services, Inc.; and ESCAID 110TM available from ExxonMobil in Houston, Texas, USA.
- Oil-based drilling fluids can provide better shale inhibition, better lubrication, higher rates of
- a portion of a wellbore may be an open hole or cased hole.
- a tubing string may be placed into the wellbore.
- the tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore.
- a casing is placed into the wellbore which can also contain a tubing string.
- a wellbore can contain an annulus .
- annulus examples include, but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore .
- a cement composition in a cased-hole wellbore, can be placed into and allowed to set in an annulus between the wall of the wellbore and the outside of the casing in order to stabilize and secure the casing in the wellbore.
- cementing the casing in the wellbore fluids are prevented from flowing into the annulus. Consequently, oil or gas can be produced in a
- cement compositions can also be used in primary or secondary cementing operations, well-plugging, or squeeze cementing.
- the spacer fluid can be introduced into the wellbore after the drilling fluid and before the cement composition.
- the spacer fluid can be circulated down through a drill string or tubing string and up through an annulus. The spacer fluid functions to remove the drilling fluid from the wellbore .
- oil-based drilling fluids are generally more difficult to remove with a spacer fluid compared to water- based drilling fluids. As a result, it is common for some of the oil-based drilling fluid to remain in the well even after introducing a spacer fluid into the well.
- the remaining oil- based drilling fluid is commonly referred to as a "mud-pocket”.
- a cement composition can mix with some of the remaining oil- based drilling fluid and become "contaminated.” If some of the remaining oil-based drilling fluid mixes with the cement
- the drilling fluid can cause adverse effects on some of the properties of the cement composition.
- the rheology and compressive strength of the cement composition can be adversely affected.
- some or all of the cement composition may never set or be significantly delayed in setting .
- transition fluid containing a calcium aluminate cement can be used in lieu of, or in addition to, a spacer fluid.
- the transition fluid can be introduced into the wellbore after the introduction of an oil-based drilling fluid and before the introduction of a cement composition.
- the transition fluid functions to maintain or decrease the setting time of the cement composition and can also enhance some of the properties of the cement composition, such as the compressive strength.
- a cement composition is "mixed" according to the following procedure.
- the water is added to a mixing container and the container is then placed on a mixer base.
- the motor of the base is then turned on and maintained at 4,000 revolutions per minute (rpm) .
- the cement and any other ingredients are added to the container at a uniform rate in not more than 15 seconds (s) .
- a cover is then placed on the container, and the cement composition is mixed at 12,000 rpm (+/- 500 rpm) for 35 s (+/- 1 s) .
- An oil-based mud was obtained from the field.
- the field mud was mixed for 1 hour (hr) with a dispersator for 30 minutes (min) with a multi-mixer at 12,000 revolutions per minute (rpm) (+/- 500 rpm) prior to testing.
- a transition fluid is mixed according to the following procedure.
- a specified OBM which includes a
- hydrocarbon liquid and an aqueous internal phase is added to a mixing container, and the container is then mixed with a multi- mixer maintained at 12,000 rpm (+/- 500 rpm) for 15 min. All mixing of the transition fluid and ingredients is conducted at the same mixing speed and for the same mixing duration of 15 min after addition of each of the specified ingredients. Any additional hydrocarbon liquid, additional aqueous internal phase, calcium aluminate cement (CAC) , and any other ingredients are added directly to the container and mixed at the speed and duration specified above prior to the addition of each of the next ingredients. After addition of the last ingredient, the transition fluid is mixed for at least 15 min. It is to be understood that the cement composition, OBM, and transition fluid are mixed at ambient temperature and pressure (about 71 °F (22 °C) and about 1 atm (0.1 MPa) ) .
- a "contaminated cement composition” is prepared as follows. An oil-based mud is obtained. The cement
- composition is mixed. If a transition fluid is to be
- the transition fluid is mixed.
- a specified percentage by volume of the OBM and possibly the transition fluid are mixed with the cement composition using an overhead paddle mixer at 500 rpm (+/- 250 rpm) for 5 min. All of the contaminated cement test samples and uncontaminated cement test samples were cured at 90
- test samples can be tested for a specific test after preparation of the sample.
- the sample can also be tested for a specific test after static aging of the sample in a static aging cell for 16 hr at a temperature of 250 °F (121.1 °C) and a pressure of 300 pounds force per square inch (psi) (2.1 Megapascals "MPa") consisting of nitrogen gas.
- test e.g., rheology
- temperature and pressure of the test composition is adjusted up to the specified temperature and pressure after being mixed at ambient temperature and pressure.
- a cement for example, a cement
- composition can be mixed at 71 °F (22 °C) and 1 atm (0.1 MPa) and then placed into the testing apparatus and the temperature of the cement composition can be adjusted to the specified temperature. After the test composition is adjusted to the specified temperature and possibly specified pressure, the test composition is maintained at that temperature and pressure for the duration of the testing.
- a desirable property of an oil-based substance is a good electrical stability.
- the electrical stability (ES) of the substance is a property related to its emulsion stability and oil-wetting capability. ES is determined by applying a voltage-ramped, sinusoidal electrical signal across a pair of parallel, flat-plate electrodes immersed in the drilling fluid. The resulting current remains low until a threshold voltage is reached, whereupon the current rises very rapidly.
- ES threshold voltage
- ⁇ microamperes
- the "electrical stability" of an oil-based substance is measured according to API 13B-2 section 10, Recommended Practice for Field Testing of Oil-based Drilling Fluids procedure as follows. The substance is placed in a viscometer cup maintained at 50 °C ⁇ 2 °C (120 °F ⁇ 5 °F) . The substance is hand-stirred with an electrode probe for approximately 10 s to ensure that the composition and temperature of the substance are uniform. The electrode probe is positioned such that it does not touch the bottom or sides of the container and the electrode surfaces are completely covered by the substance. The voltage ramp test is conducted. The average of the two ES measurements is the ES reported in units of volts (V) .
- Rheology is a unit-less measure of how a
- Rheology includes the substance's elasticity, plasticity, and viscosity.
- the "rheology" of a substance is measured as follows. The substance is mixed. The substance is placed into the test cell of a rotational viscometer, such as a FANN® Model 35 viscometer, fitted with a Bob and Sleeve attachment and a spring number 1. The substance is tested at the specified temperature and ambient pressure, about 1 atm (0.1 MPa) . Rheology readings are taken at multiple rpm's, for example, at 600, 300, 200, 100, 6, and 3.
- a substance can develop gel strength.
- the "initial gel strength" of a substance is measured according to API 13B-2 section 6.3, Recommended Practice for Field Testing of Oil-based Drilling Fluids as follows. After the rheology testing of the substance is performed, the
- the "10 min gel strength” is measured as follows. After the initial gel strength test has been
- the "plastic viscosity" (PV) of a substance is obtained from the Bingham-Plastic rheological model and calculated as the difference between the 600 rpm and 300 rpm dial readings from the rheology testing, expressed in units of cP.
- the yield point (YP) is defined as the value obtained from the Bingham-Plastic rheological model when
- yield point of a substance is calculated as the difference between the plastic viscosity and the 300 rpm dial reading, expressed in units of lb/100 ft 2 .
- a substance can develop compressive strength.
- cement composition compressive strengths can vary from 0 psi to over 10,000 psi (0 to over 69 MPa) .
- Compressive strength is generally measured at a specified time after the substance has been mixed and at a specified
- Compressive strength can be measured, for example, at a time of 24 hours. Compressive strength can be measured by either a destructive method or non-destructive method .
- compression strength of a substance is measured at ambient temperature (about 71 °F, about 22 °C) as follows.
- the substance is mixed.
- the substance is then placed into a test cell for at least 24 hours at a temperature of 90 °F (32.2 °C) until the substance has set.
- the set substance is then removed from the test cell and the set substance is then placed into a compression-testing device, such as a Carver Press testing machine model 4350 L, available from Carver Inc. in Indiana, USA.
- the pressure is gradually increased until the substance breaks.
- the destructive compressive strength is calculated as the force required to break the substance divided by the smallest cross-sectional area in contact with the load-bearing plates of the compression-testing device.
- the destructive compressive strength is reported in units of pressure, such as pound-force per square inch (psi) or megapascals (MPa) .
- a transition fluid comprises: a hydrocarbon liquid, wherein the hydrocarbon liquid is the external phase of the transition fluid; an aqueous liquid, wherein the aqueous liquid is the internal phase of the transition fluid and wherein the aqueous liquid comprises a water-soluble salt; and a calcium aluminate cement.
- a method of cementing in a subterranean formation comprises: introducing the transition fluid into the subterranean formation;
- composition is performed after the step of introducing the transition fluid and wherein the cement composition comprises cement and water.
- the transition fluid comprises a hydrocarbon liquid, wherein the hydrocarbon liquid is the external phase of the transition fluid.
- the hydrocarbon liquid can be synthetic.
- the hydrocarbon liquid can be selected from the group consisting of: a fractional distillate of crude oil; a fatty derivative of an acid, an ester, an ether, an alcohol, an amine, an amide, or an imide; a saturated hydrocarbon; an unsaturated hydrocarbon; a branched hydrocarbon; a cyclic hydrocarbon; and any combination thereof.
- Crude oil can be separated into fractional distillates based on the boiling point of the fractions in the crude oil.
- An example of a suitable fractional distillate of crude oil is diesel oil.
- a commercially-available example of a fatty acid ester is PETROFREE® ESTER base fluid, marketed by Halliburton Energy Services, Inc.
- the saturated hydrocarbon can be an alkane or paraffin.
- the paraffin can be an isoalkane
- isoparaffin a linear alkane (paraffin), or a cyclic alkane (cycloparaffin) .
- An example of an alkane is BAROID ALKANETM base fluid, marketed by Halliburton Energy Services, Inc.
- suitable paraffins include, but are not limited to: BIO-BASE 360® (an isoalkane and n-alkane) ; BIO-BASE 300TM (a linear alkane) ; BIO-BASE 560® (a blend containing greater than 90% linear alkanes); and ESCAID 110TM (a mineral oil blend of mainly alkanes and cyclic alkanes) .
- BIO-BASE liquids are available from Shrieve Chemical Products, Inc.
- the ESCAID liquid is available from ExxonMobil in Houston, TX.
- the unsaturated hydrocarbon can be an alkene, alkyne, or aromatic.
- the alkene can be an isoalkene, linear alkene, or cyclic alkene.
- the linear alkene can be a linear alpha olefin or an internal olefin.
- An example of a linear alpha olefin is NOVATECTM, available from M-I SWACO in Houston, TX.
- Examples of internal olefins-based drilling fluids include, ENCORE® drilling fluid and ACCOLADE® internal olefin and ester blend drilling fluid, marketed by Halliburton Energy Services, Inc.
- An example of a diesel oil-based drilling fluid is INVERMUL ® , marketed by
- the transition fluid includes an aqueous liquid.
- the aqueous liquid is the internal phase of the transition fluid. There can also be more than one internal phase of the transition fluid.
- the aqueous liquid comprises water and a water-soluble salt.
- the aqueous liquid can be selected from the group consisting of freshwater, brackish water, and saltwater, in any combination thereof in any proportion.
- the salt for the aqueous liquid can be selected from the group consisting of sodium chloride, calcium chloride, calcium bromide, potassium chloride, potassium bromide, magnesium chloride, and any
- the salt is in a concentration in the range of about 15% to about 40% by weight of the water.
- the salt can also be in a concentration such that the aqueous liquid has a water phase salinity in the range of about 100,000 to about 400,000 parts per million (ppm) , preferably about 150,000 to about 300,000 ppm.
- the salt can also be in a concentration such that the amount of available free water is in a desired amount.
- the desired amount of free water available can be an amount whereby the least amount of calcium aluminate cement (CAC) chemically reacts with the free water. In this manner, during introduction of the transition fluid into the subterranean formation, the CAC does not begin to thicken or begin to set. It is to be
- the transition fluid is in a pumpable state during the step of introducing the transition fluid into the subterranean
- the salt can also be in a concentration such that the transition fluid has a desired density.
- the desired density is a density similar to the density of a drilling fluid used in forming a wellbore in the subterranean formation.
- the term "similar” means within +/- 10%.
- the desired density is in the range of about 8 to about 20 pounds per gallon (ppg) (about 0.959 to about 2.397 kilograms per liter "kg/L”), preferably about 10 to about 16 ppg (about 1.198 to about 1.917 kg/L) .
- the transition fluid includes calcium aluminate cement (CAC) .
- the CAC comprises at least calcium, aluminum, and oxygen.
- the CAC comprises aluminum oxide (AI 2 O 3 ) and calcium oxide (CaO) .
- the CAC can also include silicon dioxide (S1O 2 ), iron III oxide (Fe 2 ⁇ 0 3 ) , and other
- the aluminum oxide can be present in the CAC in an amount in the range of about 30 weight (wt.) % to about 80 wt . %, alternatively from about 40 wt. % to about 70 wt . %, or alternatively from about 50 wt. % to about 60 wt . %, based upon the total weight of the CAC.
- the calcium oxide can be present in the CAC in an amount in the range of about 20 wt. % to about 60 wt . %, alternatively from about 30 wt. % to about 50 wt . %, or alternatively from about 35 wt. % to about 40 wt . %, based upon the total weight of the CAC.
- the aluminum oxide to calcium oxide (Al 2 0 3 /CaO) weight ratio in the CAC may vary from about 1:1 to about 4:1, alternatively from about 2:1 to about 1.5:1.
- An example of a commercially-available calcium aluminate cement is THERMALOCKTM, marketed by Halliburton Energy Services, Inc. and SECAR ® 51, available from Kerneos Inc. in Chesapeake, Virginia.
- the CAC is in a sufficient concentration such that the transition fluid is capable of providing a compressive strength of at least 900 psi (6.2 MPa) to a contaminated cement composition comprising cement and water, and having 10% by volume contamination with the transition fluid at a curing temperature of 90 °F (32.2 °C) and a time of at least 24 hours.
- the CAC is in a concentration of at least 25 pounds per barrel (ppb) of the transition fluid.
- the CAC can also be in concentration in the range of about 25 to about 200 ppb, preferably about 50 to about 150 ppb of the transition fluid.
- the transition fluid can further comprise a surfactant.
- a surfactant is amphiphilic, comprising a
- hydrophobic tail group and a hydrophilic head group If a surfactant is in a sufficient concentration in a solution, then the surfactant molecules can form micelles.
- a "micelle" is an aggregate of surfactant molecules dispersed in a solution.
- a surfactant in an oil solution can form reverse-micelles with the hydrophobic tails in contact with the hydrocarbon solvent, sequestering the hydrophilic heads in the center of the reverse- micelle.
- a surfactant in an aqueous solution can form micelles with the hydrophilic heads in contact with the aqueous solvent, sequestering the hydrophobic tails in the micelle center.
- the surfactant must be in a sufficient
- the critical micelle concentration is the concentration of surfactant above which reverse-micelles or micelles are spontaneously formed.
- the surfactant is a water-wetting agent.
- the surfactant is capable of forming micelles.
- the surfactant is capable of decreasing the plastic viscosity of the transition fluid compared to a transition fluid without the surfactant.
- the surfactant can also be capable of decreasing the 10 s and 10 min gel strength of the transition fluid.
- the surfactant does not delay the setting time of the cement
- the surfactant has a concentration greater than or equal to the critical micelle concentration. According to another embodiment, the surfactant is in a concentration such that a test transition fluid
- the transition fluid consisting essentially of the hydrocarbon liquid, the aqueous liquid, the CAC, and the surfactant, and in the same proportions as the transition fluid has a lower plastic viscosity (PV) than a substantially identical test transition fluid without the surfactant when tested at a temperature of 120 °F (48.9 °C) .
- PV plastic viscosity
- substantially identical means the fluid contains the same ingredients, concentrations of
- the surfactant can also be in a
- the surfactant can also be in a sufficient concentration such that the transition fluid has a desired PV.
- the desired PV can be in the range of about 10 to about 150 centipoise (cP) , preferably about 35 to about 85 cP .
- the desired PV can also be a PV such that the transition fluid remains in a pumpable state during introduction into the
- surfactant is in a concentration of at least 0.10 pounds per barrel (lb/bbl) of the transition fluid.
- the surfactant can also be in a concentration in the range of about 0.10 to about 20 lb/bbl of the transition fluid, preferably about 5 to about 10 lb/bbl of the transition fluid.
- the transition fluid has a plastic viscosity in the range of about 10 to about 150 centipoise (cP) , preferably about 35 to about 85 cP, at the bottomhole temperature and pressure of the subterranean
- the term "bottomhole” means the portion of the subterranean formation to be treated.
- the transition fluid has a density in the range of about 8 to about 20 pounds per gallon (ppg) (about 0.959 to about 2.397 kilograms per liter "kg/L”), preferably about 10 to about 16 ppg (about 1.198 to about 1.917 kg/L), at the bottomhole temperature and pressure of the subterranean formation.
- the transition fluid is in a pumpable state during introduction into the subterranean formation.
- the "pumpability" of a fluid is related to the consistency of the fluid.
- a fluid is considered pumpable if the fluid has a consistency of less than or equal to 70 Bearden units of consistency (Be) .
- the transition fluid has a consistency less than or equal to 70 Be during introduction into the formation.
- the thickening time of a fluid is the time it takes for a fluid to reach greater than 70 Be.
- the transition fluid has a thickening time of at least 30 min, preferably at least 1 hour, and more preferably the time it takes to introduce the transition fluid into the portion of the subterranean formation.
- transition fluid can be encapsulated such that the transition fluid remains pumpable and has the desired thickening time.
- the encapsulating material can be designed such that the material dissolves at a pre-determined time.
- the transition fluid can also contain other ingredients.
- the other ingredients can include a friction reducer, a strength-retrogression additive, a light-weight additive, a defoaming agent, a high-density additive, a
- the methods include the step of introducing the transition fluid into the subterranean formation.
- the methods can further include the step of forming the transition fluid.
- the step of forming can include preparing the transition fluid on-the-fly at a well site.
- the methods can further include the step of introducing an oil-based drilling fluid into the
- step of introducing the oil- based drilling fluid is performed prior to the step of
- the transition fluid has a density similar to the oil-based drilling fluid.
- the density of the oil-based drilling fluid is less than the necessary density such that premature fracturing of the subterranean formation could occur.
- the transition fluid has a plastic viscosity similar to the oil-based drilling fluid.
- the step of forming the transition fluid can also include obtaining a volume of the oil-based drilling fluid and mixing the CAC; possibly the surfactant, additional hydrocarbon liquid, and additional aqueous internal phase; and any other ingredients with the oil-based drilling fluid.
- the oil-based drilling fluid comprises at least a portion of the hydrocarbon liquid external phase and the aqueous liquid internal phase.
- the methods can further include the step of introducing a spacer fluid into the subterranean formation.
- the step of introducing the spacer fluid can be performed before or after the introduction of the transition fluid. More than one spacer fluid can also be introduced into the subterranean formation. According to this embodiment, a first spacer fluid can be introduced before the transition fluid and a second spacer fluid can be introduced after the transition fluid.
- the spacer fluid is introduced after the
- the spacer fluid is introduced prior to the step of introducing the cement composition.
- the methods include the step of introducing the cement composition into the subterranean formation, wherein the step of introducing the cement composition is performed after the step of introducing the transition fluid.
- the cement composition can be in a pumpable state before and during
- the subterranean formation can be a reservoir or adjacent to a reservoir.
- the subterranean formation can be penetrated by a well.
- the step of introducing the fluids and composition can include introducing the fluids or composition into the well.
- the well can be without limitation, an oil, gas, or water production well, or an injection well.
- the step of introducing the cement composition can be for the purpose of at least one of the following: well completion, primary or secondary cementing operations, well-plugging, squeeze cementing, or gravel packing operations .
- the cement composition comprises cement.
- the cement can be Class A cement, Class C cement, Class G cement, Class H cement, and any combination thereof.
- the cement is Class G cement or Class H cement.
- the cement can be, without limitation, Portland cement, Joppa cement, Dyckerhoff cement, and any combination thereof.
- the cement can also be a calcium aluminate cement.
- the cement composition also includes water.
- the water can be selected from the group consisting of freshwater, brackish water, and saltwater, in any combination thereof in any proportion.
- the cement composition can further comprise a water-soluble salt.
- the salt can be selected from sodium chloride, calcium chloride, calcium bromide, potassium chloride, potassium bromide, magnesium chloride, and any combination thereof in any proportion.
- the salt is in a
- the cement composition has a density of at least 8 ppg (0.959 kg/L) .
- the cement composition can have a density in the range of about 8 to about 22 ppg (about 0.959 to about 2.636 kg/L) .
- the cement composition can further include other additives.
- other additives include, but are not limited to, a filler, a fluid loss additive, a set retarder, a friction reducer, a set accelerator, a thinner, a strength- retrogression additive, a light-weight additive, a defoaming agent, a high-density additive, a mechanical property enhancing additive, a lost-circulation material, a filtration-control additive, a thixotropic additive, and combinations thereof.
- the cement composition can include a filler.
- fillers include, but are not limited to, fly ash, sand, clays, and vitrified shale.
- the filler is in a concentration in the range of about 5% to about 50% by weight of the cement (bwoc) .
- the cement composition can include a fluid loss additive.
- Suitable examples of commercially-available fluid loss additives include, but are not limited to, and are marketed by Halliburton Energy Services, Inc. under the tradenames
- the fluid loss additive is in a concentration in the range of about 0.05% to about 10% bwoc.
- the cement composition can include a set
- set retarder Suitable examples of commercially-available set retarders include, but are not limited to, and are marketed by Halliburton Energy Services, Inc. under the tradenames HR®-4, HR®-5, HR®-6, HR®-12, HR®-20, HR®-25, SCR-100TM, and SCR-500TM.
- the set retarder is in a concentration in the range of about 0.05% to about 10% bwoc.
- the cement composition can include a friction reducer.
- Suitable examples of commercially-available friction reducers include, but are not limited to, and are marketed by Halliburton Energy Services, Inc. under the tradenames CFR-2TM, CFR-3TM, CFR-5LETM, CFR-6TM, and CFR-8TM.
- the friction reducer is in a concentration in the range of about 0.1% to about 10% bwoc.
- the cement composition can include a strength- retrogression additive.
- Suitable examples of commercially- available strength-retrogression additives include, but are not limited to, and are marketed by Halliburton Energy Services, Inc. under the tradenames SSA-1TM and SSA-2TM.
- the strength-retrogression additive is in a concentration in the range of about 5% to about 50% bwoc.
- the cement composition can include a light-weight additive.
- Suitable examples of commercially-available light ⁇ weight additives include, but are not limited to, and are marketed by Halliburton Energy Services, Inc. under the
- the light-weight additive is in a
- additives include, but are not limited to, HIGH DENSE® No. 3, HIGH DENSE® No. 4, BARITETM, and MICROMAXTM, heavy-weight
- SILICALITETM extender and compressive-strength enhancer
- WELLLIFE ® 665 WELLLIFE ® 809
- WELLLIFE ® 810 mechanical property enhancers, marketed by Halliburton Energy Services, Inc.
- the methods can further include the step of allowing the cement composition to set.
- the step of allowing can be performed after the step of introducing the cement composition into the subterranean formation.
- the transition fluids contained a drilling base fluid in units of barrels (bbl) containing diesel oil as the hydrocarbon liquid external phase and a calcium chloride brine at a water phase salinity concentration of 250,000 parts per million (ppm) as the aqueous liquid in varying oil-to-water ratios (OWR) .
- the drilling base fluid also contained other ingredients, such as an emulsifier, a filtration control agent, a viscosifier, and barite.
- Fluids 2, 3, and 4 also contained SECAR ® 51 calcium aluminate cement at a concentration of 100 pounds per barrel (lb/bbl) .
- Fluid D also contained ENVIROGEM ® 360 surfactant at a concentration of 10 lb/bbl.
- the density for each fluid is listed in units of pounds per gallon (lb/gal) .
- transition fluids were mixed and tested according to the procedure for the specific test as described in The Detailed Description section above.
- the "base” fluid data was conducted before static aging.
- the “aged” fluid data was conducted after static aging the sample for 16 hours at a temperature of 250 °F (121.1 °C) and a pressure of 300 psi (2.1 MPa) consisting of nitrogen gas.
- the rheology and electrical stability (ES) tests were conducted at a pressure of 1 atm and a temperature of 120 °F (48.9 °C) .
- Table 1 contains electrical stability (ES), plastic viscosity (PV) , yield point (YP) , 10 second (s) and 10 minute (min) gel strengths, and rheology data for test fluids A through D base fluid and aged fluid.
- ES electrical stability
- PV plastic viscosity
- YP yield point
- min 10 minute
- Fluid 1 exhibited very good results.
- Fluid 3 exhibited a lower ES for the base and aged fluids and lower PV, YP, gel strengths, and rheology for the base fluid compared to Fluid 2.
- the rheology of Fluid 3 dramatically increased after aging.
- Fluid 4 exhibited better than or comparable results to Fluid 1. This indicates that the addition of the surfactant to the transition fluid yields a transition fluid that has similar properties to a traditional invert emulsion. Fluid 4 also exhibited better results for the aged fluid compared to the aged Fluid 2 and 3.
- compositions contained 860 grams (g) Class H cement and 327 g deionized water.
- the drilling base fluids contained diesel oil as the hydrocarbon liquid external phase at a concentration of 36 lb/bbl and a calcium chloride brine at a water phase salinity concentration of 250,000 parts per million (ppm) as the aqueous liquid internal phase at a concentration of 12 lb/bbl.
- the drilling base fluids also contained other ingredients, such as an emulsifier, a filtration control agent, a viscosifier, and Barite.
- the transition fluids contained 0.73 barrels of the drilling base fluid along with SECAR ® 51 calcium aluminate cement at a concentration of 100 pounds per barrel (lb/bbl), and
- composition A As can be seen in Fig. 1, composition A
- compositions B, C, and D represent a cement composition that is contaminated with an oil- based drilling fluid. As can be seen, as the percentage of oil- based drilling fluid contamination increases, the compressive strength of the contaminated cement composition decreases. At a contamination ratio of 50:50 (composition D) , the contaminated cement composition never set.
- Compositions E through I represent a cement composition that is contaminated with an oil- based drilling fluid. As can be seen, as the percentage of oil- based drilling fluid contamination increases, the compressive strength of the contaminated cement composition decreases. At a contamination ratio of 50:50 (composition D) , the contaminated cement composition never set.
- compositions B, E, and H each representing a 90:10 contamination ratio
- the cement compositions contaminated with the transition fluid (E and H) exhibited much higher compressive strengths compared to the cement composition contaminated with the drilling base fluid (B) .
- the concentration of the CAC may need to be increased in order to provide higher compressive strengths to the contaminated cement composition.
- Table 3 lists the ingredients of each of the contaminated cement compositions and the ratios of the
- the cement compositions contained 860 grams (g) Class H cement and 327 g deionized water.
- the drilling base fluids contained an internal olefin as the hydrocarbon liquid external phase at a concentration of 62 lb/bbl and a calcium chloride brine at a water phase salinity concentration of 250,000 parts per million (ppm) as the aqueous liquid internal phase at a concentration of 47 lb/bbl.
- the drilling base fluid also contained other ingredients, such as an emulsifier, a filtration control agent, a viscosifier, and barite.
- the transition fluids contained 0.57 barrels of the drilling base fluid along with SECAR ® 51 calcium aluminate cement at a concentration of 100 pounds per barrel (lb/bbl) .
- composition A As can be seen in Fig. 2, composition A
- compositions B, C, and D represent a cement composition that is contaminated with an oil- based drilling fluid. As can be seen, as the percentage of oil- based drilling fluid contamination increases, the compressive strength of the contaminated cement composition decreases. At a contamination ratio of 50:50 (composition D) , the contaminated cement composition never set.
- Compositions E, F, and G represent a cement composition that is contaminated with an oil- based drilling fluid. As can be seen, as the percentage of oil- based drilling fluid contamination increases, the compressive strength of the contaminated cement composition decreases. At a contamination ratio of 50:50 (composition D) , the contaminated cement composition never set.
- compositions B and E, and C and F represent a cement composition that is contaminated with the transition fluid.
- the cement compositions contaminated with the transition fluid (E and F) exhibited much higher compressive strengths compared to the cement compositions contaminated with the drilling base fluid (B and C) . This indicates that the presence of the calcium aluminate cement in the transition fluid is capable of increasing the compressive strength of the
- transition fluid functions well to increase compressive strength in both diesel oil and an internal olefin hydrocarbon liquid. This indicates that the transition fluid can be easily formulated based on different types of oil-based drilling fluids being used at a well site.
- the exemplary fluids and additives disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation,
- the disclosed fluids and additives may directly or indirectly affect one or more mixers, related mixing equipment, mud pits, storage
- the disclosed fluids and additives may also directly or indirectly affect any transport or delivery equipment used to convey the fluids and additives to a well site or downhole such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the fluids and additives from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive the fluids and additives into motion, any valves or related joints used to regulate the pressure or flow rate of the fluids, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like.
- the disclosed fluids and additives may also directly or
- fluids and additives such as, but not limited to, drill string, coiled tubing, drill pipe, drill collars, mud motors, downhole motors and/or pumps, floats,
- roller cone including roller cone, PDC, natural diamond, hole openers, reamers, and coring bits
- sensors or distributed sensors including roller cone, PDC, natural diamond, hole openers, reamers, and coring bits
- downhole heat exchangers including roller cone, PDC, natural diamond, hole openers, reamers, and coring bits
- valves and corresponding actuation devices including tool seals, packers and other wellbore isolation devices or components, and the like.
- compositions and methods also can “consist essentially of” or values (of the form, "from about a to about b, " or,
Landscapes
- Chemical & Material Sciences (AREA)
- Engineering & Computer Science (AREA)
- Materials Engineering (AREA)
- Organic Chemistry (AREA)
- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Ceramic Engineering (AREA)
- Inorganic Chemistry (AREA)
- Structural Engineering (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Soil Conditioners And Soil-Stabilizing Materials (AREA)
- Civil Engineering (AREA)
- Environmental & Geological Engineering (AREA)
- Dispersion Chemistry (AREA)
- Combustion & Propulsion (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Curing Cements, Concrete, And Artificial Stone (AREA)
Abstract
Description
Claims
Priority Applications (6)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
AU2013309445A AU2013309445B2 (en) | 2012-08-30 | 2013-05-23 | An invert emulsion transition fluid containing calcium aluminate cement |
EP13834039.3A EP2890658B1 (en) | 2012-08-30 | 2013-05-23 | An invert emulsion transition fluid containing calcium aluminate cement |
BR112015001779A BR112015001779A2 (en) | 2012-08-30 | 2013-05-23 | cementation method in an underground formation, and transition fluid |
EA201492051A EA201492051A1 (en) | 2012-08-30 | 2013-05-23 | TRANSITIONAL CURRENT ENVIRONMENT, PRESENTING REVERSE EMULSION, CONTAINING CALCIUM ALUMINUM CEMENT |
CA2877689A CA2877689C (en) | 2012-08-30 | 2013-05-23 | An invert emulsion transition fluid containing calcium aluminate cement |
MX2014014873A MX2014014873A (en) | 2012-08-30 | 2013-05-23 | An invert emulsion transition fluid containing calcium aluminate cement. |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/599,978 US9663702B2 (en) | 2012-08-30 | 2012-08-30 | Invert emulsion transition fluid containing calcium aluminate cement |
US13/599,978 | 2012-08-30 |
Publications (1)
Publication Number | Publication Date |
---|---|
WO2014035499A1 true WO2014035499A1 (en) | 2014-03-06 |
Family
ID=50184091
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2013/042395 WO2014035499A1 (en) | 2012-08-30 | 2013-05-23 | An invert emulsion transition fluid containing calcium aluminate cement |
Country Status (8)
Country | Link |
---|---|
US (1) | US9663702B2 (en) |
EP (1) | EP2890658B1 (en) |
AU (1) | AU2013309445B2 (en) |
BR (1) | BR112015001779A2 (en) |
CA (1) | CA2877689C (en) |
EA (1) | EA201492051A1 (en) |
MX (1) | MX2014014873A (en) |
WO (1) | WO2014035499A1 (en) |
Families Citing this family (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US11746276B2 (en) * | 2018-10-11 | 2023-09-05 | Saudi Arabian Oil Company | Conditioning drilling fluid |
Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20050022990A1 (en) * | 2003-07-31 | 2005-02-03 | Jiten Chatterji | Compositions and methods for preventing coagulation of water-in-oil emulsion polymers in aqueous saline well treating fluids |
US20060054320A1 (en) * | 2004-09-14 | 2006-03-16 | Brothers Lance E | Subterranean fluids having improved environmental characteristics and methods of using these fluids in subterranean formations |
US20080110619A1 (en) * | 2004-02-10 | 2008-05-15 | Roddy Craig W | Methods of using substantially hydrated cement particulates in subterranean applications |
EP2457974A1 (en) * | 2010-11-05 | 2012-05-30 | Services Pétroliers Schlumberger | Cement compositions and methods for well completions |
Family Cites Families (42)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3850248A (en) * | 1973-11-19 | 1974-11-26 | Halliburton Co | Method of using a spacer fluid for spacing drilling muds and cement |
US4276182A (en) * | 1978-05-19 | 1981-06-30 | The Western Company Of North America | High temperature cement mud spacer |
US4700780A (en) * | 1987-03-27 | 1987-10-20 | Halliburton Services | Method of reducing fluid loss in cement compositions which may contain substantial salt concentrations |
US5020598A (en) | 1989-06-08 | 1991-06-04 | Shell Oil Company | Process for cementing a well |
US5058679A (en) | 1991-01-16 | 1991-10-22 | Shell Oil Company | Solidification of water based muds |
US5458197A (en) * | 1991-01-30 | 1995-10-17 | Atlantic Richfield Company | Well cleanout system and method |
US5327968A (en) | 1992-12-30 | 1994-07-12 | Halliburton Company | Utilizing drilling fluid in well cementing operations |
US5333690A (en) * | 1992-12-31 | 1994-08-02 | Shell Oil Company | Cementing with blast furnace slag using spacer |
US5305831A (en) | 1993-02-25 | 1994-04-26 | Shell Oil Company | Blast furnace slag transition fluid |
US5383521A (en) | 1993-04-01 | 1995-01-24 | Halliburton Company | Fly ash cementing compositions and methods |
US5458195A (en) | 1994-09-28 | 1995-10-17 | Halliburton Company | Cementitious compositions and methods |
US5585333A (en) | 1994-10-12 | 1996-12-17 | Halliburton Company | Hydrocarbon base cementitious drilling fluids and methods |
US5711383A (en) | 1996-04-19 | 1998-01-27 | Halliburton Company | Cementitious well drilling fluids and methods |
US6796378B2 (en) | 1997-08-15 | 2004-09-28 | Halliburton Energy Services, Inc. | Methods of cementing high temperature wells and cement compositions therefor |
AU738096B2 (en) | 1997-08-15 | 2001-09-06 | Halliburton Energy Services, Inc. | Light weight high temperature well cement compositions and methods |
US5900053A (en) | 1997-08-15 | 1999-05-04 | Halliburton Energy Services, Inc. | Light weight high temperature well cement compositions and methods |
US6663778B1 (en) * | 1999-10-12 | 2003-12-16 | Mansour S. Bader | Process for the treatment of aqueous streams containing inorganics |
US6244343B1 (en) | 2000-03-09 | 2001-06-12 | Halliburton Energy Services, Inc. | Cementing in deep water offshore wells |
US6887832B2 (en) | 2000-12-29 | 2005-05-03 | Halliburton Energy Service,S Inc. | Method of formulating and using a drilling mud with fragile gels |
US7456135B2 (en) | 2000-12-29 | 2008-11-25 | Halliburton Energy Services, Inc. | Methods of drilling using flat rheology drilling fluids |
US7696131B2 (en) | 2002-06-19 | 2010-04-13 | Halliburton Energy Services, Inc. | Diesel oil-based invert emulsion drilling fluids and methods of drilling boreholes |
US6722433B2 (en) | 2002-06-21 | 2004-04-20 | Halliburton Energy Services, Inc. | Methods of sealing expandable pipe in well bores and sealing compositions |
US7147067B2 (en) | 2002-12-10 | 2006-12-12 | Halliburton Energy Services, Inc. | Zeolite-containing drilling fluids |
US7198104B2 (en) | 2003-08-12 | 2007-04-03 | Halliburton Energy Services, Inc. | Subterranean fluids and methods of cementing in subterranean formations |
US7448450B2 (en) | 2003-12-04 | 2008-11-11 | Halliburton Energy Services, Inc. | Drilling and cementing with fluids containing zeolite |
US7086466B2 (en) | 2004-02-10 | 2006-08-08 | Halliburton Energy Services, Inc. | Use of substantially hydrated cement particulates in drilling and subterranean applications |
US7259130B2 (en) | 2004-08-03 | 2007-08-21 | Halliburton Energy Services, Inc. | Set-on demand, ester-based wellbore fluids and methods of using the same |
US7150322B2 (en) * | 2004-08-24 | 2006-12-19 | Halliburton Energy Services, Inc. | Cement compositions comprising environmentally compatible defoamers and methods of use |
US7341985B2 (en) | 2004-10-08 | 2008-03-11 | Air Products And Chemicals, Inc. | 2-Hydroxy-3-alkoxypropyl sulfides, sulfones, and sulfoxides: new surface active agents |
US7284608B2 (en) | 2004-10-26 | 2007-10-23 | Halliburton Energy Services, Inc. | Casing strings and methods of using such strings in subterranean cementing operations |
US7803743B2 (en) * | 2005-06-06 | 2010-09-28 | Baker Hughes Incorporated | Invert emulsion carrier fluid and oil-wetting agent and method of using same |
US8522873B2 (en) | 2005-09-09 | 2013-09-03 | Halliburton Energy Services, Inc. | Spacer fluids containing cement kiln dust and methods of use |
US7381263B2 (en) | 2005-10-24 | 2008-06-03 | Halliburton Energy Services, Inc. | Cement compositions comprising high alumina cement and cement kiln dust |
US7337842B2 (en) | 2005-10-24 | 2008-03-04 | Halliburton Energy Services, Inc. | Methods of using cement compositions comprising high alumina cement and cement kiln dust |
US7284609B2 (en) | 2005-11-10 | 2007-10-23 | Halliburton Energy Services, Inc. | Methods of using settable spotting compositions comprising cement kiln dust |
US7199086B1 (en) | 2005-11-10 | 2007-04-03 | Halliburton Energy Services, Inc. | Settable spotting compositions comprising cement kiln dust |
US7204310B1 (en) | 2006-04-11 | 2007-04-17 | Halliburton Energy Services, Inc. | Methods of use settable drilling fluids comprising cement kiln dust |
US7338923B2 (en) | 2006-04-11 | 2008-03-04 | Halliburton Energy Services, Inc. | Settable drilling fluids comprising cement kiln dust |
US8685901B2 (en) * | 2007-01-30 | 2014-04-01 | Halliburton Energy Services, Inc. | Wellbore servicing compositions and methods of using same |
US7863224B2 (en) | 2009-03-17 | 2011-01-04 | Halliburton Energy Services Inc. | Wellbore servicing compositions comprising a set retarding agent and methods of making and using same |
US8316933B2 (en) * | 2009-08-28 | 2012-11-27 | Geo Fossil Fuels Llc | Microbial enhanced oil recovery methods |
US8763705B2 (en) * | 2011-03-25 | 2014-07-01 | Schlumberger Technology Corporation | Compositions and methods for cleaning a wellbore prior to cementing |
-
2012
- 2012-08-30 US US13/599,978 patent/US9663702B2/en not_active Expired - Fee Related
-
2013
- 2013-05-23 CA CA2877689A patent/CA2877689C/en not_active Expired - Fee Related
- 2013-05-23 EP EP13834039.3A patent/EP2890658B1/en not_active Not-in-force
- 2013-05-23 WO PCT/US2013/042395 patent/WO2014035499A1/en active Application Filing
- 2013-05-23 AU AU2013309445A patent/AU2013309445B2/en not_active Ceased
- 2013-05-23 MX MX2014014873A patent/MX2014014873A/en unknown
- 2013-05-23 EA EA201492051A patent/EA201492051A1/en unknown
- 2013-05-23 BR BR112015001779A patent/BR112015001779A2/en not_active Application Discontinuation
Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20050022990A1 (en) * | 2003-07-31 | 2005-02-03 | Jiten Chatterji | Compositions and methods for preventing coagulation of water-in-oil emulsion polymers in aqueous saline well treating fluids |
US20080110619A1 (en) * | 2004-02-10 | 2008-05-15 | Roddy Craig W | Methods of using substantially hydrated cement particulates in subterranean applications |
US20060054320A1 (en) * | 2004-09-14 | 2006-03-16 | Brothers Lance E | Subterranean fluids having improved environmental characteristics and methods of using these fluids in subterranean formations |
EP2457974A1 (en) * | 2010-11-05 | 2012-05-30 | Services Pétroliers Schlumberger | Cement compositions and methods for well completions |
Also Published As
Publication number | Publication date |
---|---|
US9663702B2 (en) | 2017-05-30 |
MX2014014873A (en) | 2015-06-17 |
AU2013309445A1 (en) | 2015-01-22 |
CA2877689C (en) | 2017-03-21 |
EP2890658A4 (en) | 2016-04-27 |
BR112015001779A2 (en) | 2017-07-04 |
EA201492051A1 (en) | 2015-08-31 |
CA2877689A1 (en) | 2014-03-06 |
EP2890658A1 (en) | 2015-07-08 |
US20140060835A1 (en) | 2014-03-06 |
EP2890658B1 (en) | 2018-12-12 |
AU2013309445B2 (en) | 2016-02-11 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US11136489B2 (en) | Lime-based cement composition | |
US8459356B2 (en) | Cement composition containing a substituted ethoxylated phenol surfactant for use in an oil-contaminated well | |
GB2540096B (en) | Liquid concentrate of a strength retrogression additive | |
CA2831834C (en) | A drilling fluid that when mixed with a cement composition enhances physical properties of the cement composition | |
NO20170665A1 (en) | Acid-soluble cement composition | |
US9738821B2 (en) | Amphoteric polymer suspending agent for use in calcium aluminate cement compositions | |
NO20170612A1 (en) | Cement Compositions Having Fast Setting Times and High Compressive Strengths | |
AU2013309445B2 (en) | An invert emulsion transition fluid containing calcium aluminate cement |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
121 | Ep: the epo has been informed by wipo that ep was designated in this application |
Ref document number: 13834039 Country of ref document: EP Kind code of ref document: A1 |
|
WWE | Wipo information: entry into national phase |
Ref document number: MX/A/2014/014873 Country of ref document: MX |
|
WWE | Wipo information: entry into national phase |
Ref document number: 201492051 Country of ref document: EA Ref document number: 2013834039 Country of ref document: EP |
|
ENP | Entry into the national phase |
Ref document number: 2877689 Country of ref document: CA |
|
ENP | Entry into the national phase |
Ref document number: 2013309445 Country of ref document: AU Date of ref document: 20130523 Kind code of ref document: A |
|
NENP | Non-entry into the national phase |
Ref country code: DE |
|
REG | Reference to national code |
Ref country code: BR Ref legal event code: B01A Ref document number: 112015001779 Country of ref document: BR |
|
ENP | Entry into the national phase |
Ref document number: 112015001779 Country of ref document: BR Kind code of ref document: A2 Effective date: 20150127 |