Title of Invention	A PROCESS FOR PREPARING RELATIVE PERMEABILITY MODIFIER BIO POLYMER GEL FOR BLOCKING / LIMITING WATER PRODUCTION IN OIL SANDS
Abstract	A process for preparing relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands comprising the steps of: a. admixing the xanthan gum solution of 1500-3000 ppm in brine solution of 10000 ppm and hydrating at least for one hour, b. adjusting the pH of the above admixture from 6.5 to 7 with the help of NaOH or HCI, c. adding sodium sulphite (Na2S0) solution of 25 to 50 ppm in NaCI Solution of 10,000 ppm for acting as a oxygen scavenger to the above prepared solution, d. adding 0.1 to 1% of Calcium chloride solution in fresh water, Isopropyl alcohol solution of 1500-3000 ppm in fresh water, Thiourea H2NCSNH2 solution of 750 to 1500 ppm in fresh water for acting as anti oxidant and 0.5 to 3% of Formaldehyde solution for acting as biocide to the above prepared solution, e. preparing Chromium Acetate ,the cross linking agent solution of 50 to 1000 ppm in NaCI Solution of 10,000 ppm and mixing the same with an aqueous polymer mixture to produce the gelation solution and the said solution is added to the admixture of step d to form relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands.

Title of Invention

A PROCESS FOR PREPARING RELATIVE PERMEABILITY MODIFIER BIO POLYMER GEL FOR BLOCKING / LIMITING WATER PRODUCTION IN OIL SANDS

Abstract

A process for preparing relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands comprising the steps of: a. admixing the xanthan gum solution of 1500-3000 ppm in brine solution of 10000 ppm and hydrating at least for one hour, b. adjusting the pH of the above admixture from 6.5 to 7 with the help of NaOH or HCI, c. adding sodium sulphite (Na2S0) solution of 25 to 50 ppm in NaCI Solution of 10,000 ppm for acting as a oxygen scavenger to the above prepared solution, d. adding 0.1 to 1% of Calcium chloride solution in fresh water, Isopropyl alcohol solution of 1500-3000 ppm in fresh water, Thiourea H2NCSNH2 solution of 750 to 1500 ppm in fresh water for acting as anti oxidant and 0.5 to 3% of Formaldehyde solution for acting as biocide to the above prepared solution, e. preparing Chromium Acetate ,the cross linking agent solution of 50 to 1000 ppm in NaCI Solution of 10,000 ppm and mixing the same with an aqueous polymer mixture to produce the gelation solution and the said solution is added to the admixture of step d to form relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands.

Full Text	Original FORM 2 THE PATENTS ACT, 1970 (39 of 1970) COMPELETE SPECIFICATION [Section 10; rule 13] A PROCESS FOR PREPARING RELATIVE PERMEABILITY MODIFIER BIO POLYMER GEL FOR BLOCKING / LIMITING WATER PRODUCTION IN OIL SANDS. M/S. INSTITUTE OF OIL & GAS PRODUCTION TECHNOLOGY, OIL AND NATURAL GAS CORPORATION LIMITED, IOGPT Bldg., Panvel, NAVI MUMBAI- 410 221., Maharashtra, India. 17 JAN 2005 GRANTED 17-1-2005 The following specification particularly describes the nature of the invention and the manner The invention relates to an improved chemical system of limiting water in oil sands by using a new relative permeability modifier gel system. Petroleum liquids are stored underground in reservoirs. Wells are drilled to take out these petroleum liquids. Generally in reservoirs there are three types of fluids stored by nature i.e. gas, oil and water. Gases being the lightest are stored on top, oil in middle and water at the bottom in the reservoir sand. The production of unwanted water leads to both lifting and water disposal costs, add environmental concerns and reduces oil production. It also necessitates additional maintenance for production equipments and down hole treating for corrosion, bacteria, scale and naturally occurring radio-active material. The total handling and disposal cost of water is about 22 % of production cost. To block the unwanted water from an oil well, the first step is to find out the exact source of water. There are many diagnostic methods to ascertain the source of water and their use also necessitate special well conditions. In the situation when water-producing zone is not known or when there is operating difficulties for diagnostic, chemicals methods can be used. The best chemical available is cement. It can be used to shut the water around well bore with channels in isolating cement sheet between well and casing, where cement particle may enter or block the perforations. Micro-fine cement can be used to further improve the penetration of cement particle into the channels. Cement and micro-fine cement give temporary relief to some extent, but when there are repeated failures of cement squeezes, chemical methods can be used. The advantage associated with chemical & polymer methods is that they can be designed and placed deeper into the reservoir and water may not be able to circumvent it easily and long lasting results are obtained. There are several methods available to block the water from oil sands. The choice of methods depends on source of water and conditions prevailing in the oil sands. Also, the conventional gels cannot be used for restricting water production in all wells. This lead to an idea of use of relative permeability modifier gel system. The present invention relates to an improvement in the design of chemical gel process. This chemical process does not require identification of water source, isolation of zone and deployment of rig. It also doesn't seal the oil sand thereby stopping the production. This process during treatment does not cause damage to the oil wells. Present invention is a chemical process of relative permeability modifier consists of a polymer, cross-linker, salts, alcohol and aldehyde. The present invention is described in the context of specific terms, which are defined as follows. The oil sand formation consists of a region where the formation volume is characterized as essentially homogeneous, continuous, 'sedimentary reservoir material. But this is inclusive of terms such as streaks, fractures, fracture networks, vugs, solution channels, caverns, washouts, cavities, etc. The oil sand formation consists of horizontal "zones" of distinctive sub-ternean material of continuous geologic properties which extend in the horizontal direction. "Vertical conformance" is a measure of the degree of geologic uniformity in permeability as one moves vertically across the formation. "Areal conformance" is a measure of the degree of geologic uniformity in permeability as one moves horizontally across the formation. A "flow profile" qualitatively describes the uniformity of fluid flow through a subterranean formation while "sweep efficiency" the quantitative analog of "flow profile." "Plugging" is a substantial reduction in permeability in a region of a formation. The term "gel" as used herein is directed to a continuous three-dimensional crosslinked polymeric network having an ultra high molecular weight. The gel contains a liquid medium such as water, which is confined within the solid polymeric network. The fusion of a liquid and a solid component into a single-phase system provides the gel with a unique phase behavior. Gels employed by the present invention have sufficient structure so as not to propagate from the confines of a plugged region into a less permeable region of the formation adjoining the plugged region once in place. The gel is qualitatively defined as "flowing" or "non-flowing" based on its ability to flow under the force of gravity when unconfined on the surface at ambient atmospheric conditions. A flowing gel flows under these conditions; a non-flowing gel does not. Nonetheless, both a non-flowing gel and a flowing gel are defined herein as having sufficient structure so as not to propagate from the confines of the desired treatment region when injected therein. "Crosslinked to completion" means that the gel composition is incapable of further crosslinking because one or both of the required reactants in the initial solution are consumed. Further crosslinking is only possible if either polymer, crosslinking agent, or both are added to the gel composition. The gel composition utilized in the present invention is comprised of Xanthan Gum a commonly known as biopolymer having biological origin and a crosslinking agent capable of crosslinking the two polymer species. The Biopolymer referred herein should be a free flowing powder (free from lumps, dirt and foreign matter) with maximum of 15% moisture content. The biopolymer should be conformant to the rheological properties if tested as below: Prepare 0.5% (W/V) solution of the biopolymer sample in distilled water containing 4% (W/V) of sodium chloride (Laboratory Reagent Grade), by stirring with Hamilton Beach mixer, at medium speed for 20 minutes. Adjust pH in the range of 8-9 by addition of IN, NaOH solution while stirring. Determine the rheological properties of the suspension at 24+ 2°C. Results in: (i) Apparent viscosity, CP -15-20 (ii) Gelo, lbs/100 sq.ft - 5 (min) (iii)"n" value at 200 & 100 rpm- 0.4 (max) The biopolymer should be conformant to the crosslinking properties if tested as below: Add 500 ml. of distilled water to 5 ml. of 3% (WjV) solution of calcium chloride (fused or LR grade) and to this solution, add 0.5%(WjV) of the sample, while stirring with Hamilton Beach mixer, at medium speed for 20 min. Add to it 0.2%(WjV) chrome alum powder (LR Grade) and stir further for 10 minutes. Adjust pH in the range of 8-9 over a period of 20 minutes by slowly adding of IN, NaOH solution, while stirring at medium speed. Determine the rheological properties of the the suspension at 24+ 2° C. Results in: Apparent viscosity, CPs -30 min Yield point Ibs/lOO sq.ft - 30 (min) Gelo, Ibs/lOO sq.ft -15 (min) Gel 10, Ibs/lOO sq.ft -30 (min) The biopolymer should be conformant to the following performance test: Prepare 0.5%(W/V) solution of the sample in distilled water by stirring with Hamilton Beach mixer, at medium speed for 20 minutes. Adjust pH in the range of 8-9 by addition of iN, NaOH solution while stirring. Add 3%(W/V) of bentonite powder and stir further for 20 minutes. Determine rheological properties and API filtration loss. Transfer this mud to ageing cell and hot roll for 18 hrs. at 100+5° C.Cool to 24+ 2° C and determine rheological parameters and API filtration loss at 24+ 2° C. Change in parameters before and after hot rolling should be as under: Apparent viscosity, CP - Shall not decrease Yield point, Ibs/lOO sq.ft - Shall not decrease API filtration loss, ml - Shall no increase The biopolymer should be conformant to the following borate sensitivity test: Prepare 0.5% weight by volume (WjV) solution of the sample in distilled water by stirring with a mixer, at medium speed for 20 minutes. Add 5 ml. of 20%WjV of hot solution of borax and stir further for 5minur.es. Result should not form a stiff gel. The crosslinking agent used in the present invention is chromium acetate. This compound includes one electropositive chromium III species and one electronegative acetate ion. Inorganic mono- and/or divalent ions, function merely to balance the electrical charge of the compound, or one or more water molecules may be associated. According to this invention there is provided a process for preparing relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands comprising the steps of: a. admixing the xanthan gum solution of 1500-3000 ppm in brine solution of 10000 ppm and hydrating at least for one hour, b. adjusting the pH of the above admixture from 6.5 to 7 with the help of NaOH or HCI, c. adding sodium sulphite Na2S03 solution of 25 to 50 ppm in NaCI Solution of 10,000 ppm for acting as a oxygen scavenger to the above prepared solution, d. adding 0.1 to 1% of Calcium chloride solution in fresh water, Isopropyl alcohol solution of 1500-3000 ppm in fresh water, Thiourea H2NCSNH2 solution of 750 to 1500 ppm in fresh water for acting as anti oxidant and 0.5 to 3% of Formaldehyde solution for acting as biocide to the above prepared solution, e. preparing Chromium Acetate, the cross linking agent solution of 50 to 1000 ppm in NaCI Solution of 10,000 ppm and mixing the same with an aqueous polymer mixture to produce the gelation solution and the said solution is added to the admixture of step d to form relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands. Surface admixing broadly encompasses inter alia mixing the solution in bulk at the surface prior to injection or simultaneously mixing the solution at or near the wellhead by in-line mixing means while injecting it. Among other alternatives, the starting materials for the crosslinking agent can be dissolved directly in the aqueous polymer mixture to form the gelation solution in a single step but with continuous agitation. The present process enables the practitioner to customize or tailor-make a gel having a predetermined gelation rate and predetermined gel properties of strength and stability from the above-described composition. The gelation rate is defined as the degree of gel formation as a function of time or, synonymously, the rate of crosslinking in the gelation solution. The degree of crosslinking may be quantified in terms of gel viscosity and/or strength. Gel strength of a non-flowing gel is defined as the coherence of the gel network or resistance to deformation under external forces. Gel strength of a flowing gel is defined as the resistance of the gel to filtration or flow. Stability is defined as either thermal or phase stability. Thermal stability is the ability of a gel to withstand temperature extremes without degradation. Phase stability is the ability of a gel to resist syneresis, which can detract from the gel structure and performance. Present invention has temperature limit of the gelation solution at the surface is the freezing point of the solution and the upper limit is essentially the thermal stability limit of the polymer and or 105°C due to the additives. Thesolution is generally maintained at tropical ambient temperature at the surface. Increasing the temperature within the prescribed range at the surface increases the gelation rate and also, increasing the total polymer concentration increases the gelation rate and ultimate gel strength at a constant ratio of polymer to crosslinking agent. The practitioner advantageously selects a predetermined gelation rate which enables preparation of the gelation solution at the surface, injection of the solution as a single uniform slug into the well bore, and displacement of the entire solution into the desired subterranean oil sand. Once in place in the desired treatment region, gelation of the solution advantageously proceeds to achieve substantially complete gelation of the solution in situ. The present gelation mechanism enables the practitioner to design a gelation solution which can be injected into a treatment region at a desired injection rate with little resistance to injectivity. The solution is preferably gelled once it is in place in the desired subterranean region to minimize lost production from shut in of the production wells. The gelation time of the gel ranges from near instantaneous for flowing gels up to 48 hours or longer for both flowing and non-flowing gels. The present process is applicable to a number of hydrocarbon recovery applications. According to one embodiment, the process is applicable as sealant in case of oil sand permeability of 1 milli darcies to 25 milli darcies if placed selectively but the to the second embodiment the process is applicable as relative permeability modifier in case of oil sand permeability of 25 milli darcies and above wherein it shows the following behavior: When this gel comes in contact with undesired water from the oil sand, which needs to be blocked causes swelling in the invented gel to offer maximum obstruction whereas when it comes in contact with oil, it acts as given in the point 2 below. Also, under the same situation when oil comes in contact with the invented gel, gel shrinks and permits oil to flow preferentially as compared to the present water as given above. In case of relative permeability modification, the solution can be bulldozed into entire high permeability zone of the oil sand formation and crosslinked to completion in-situ as either a non-flowing gel or a flowing gel. Both flowing and non-flowing gels can be used for treatment of high permeability zones of the matrix because in general neither will flow from the treatment zone upon complete gelation, a necessary condition for the present invention. However,non-flowing gels are often preferred for treatment of high permeability zones in direct communication with production wells because of their increased strength. The gels are produced in a manner, which renders them insensitive to most extreme formation conditions. The gels can be applied to the treatment of many different geological structures including high permeability zones within the formation oil sand. The gels can be stable at formation temperatures as high as 105°e. The gels are relatively insensitive to the stratigraphy of the rock and can be employed in carbonate and sandstone strata and unconsolidated or consolidated strata having varying mineralogy. Once the gels are in place, it is extremely difficult to displace the gels by physical or chemical means other than total destruction of the crosslinked network. The gels may be reversible on contact with hydrogen peroxide or sodium hypochlorite, but are substantially insoluble in the formation fluids. The following examples demonstrate the laboratory test practice and utility of the present invention but are not to be construed as limiting the scope thereof. Process Verification The invention will now be described in more details with reference to its formulation to be used in blocking the water from oil sands. Laboratory Test Procedure Polymer: Xanthan Polymer commonly termed as a Biopolymer due to its origin was used for present study. A solution of 1500 - 3000 ppm was prepared in 10,000ppm NaCi solution. Solution was allowed to hydrate for minimum one hour on a magnetic stirrer. The pH of polymer solution was adjusted with NaOH or HCI. Chromium (III) [Cr(CH3COO)3] : Reagent grade chromium acetate was used. A solution of 50 - 1000 ppm in 10,000-ppm salt solution was prepared. Fresh solution of chromic acetate has bluish color but after 24 hrs due to hydration its color changes to dark blue. Cr(III) acetate solution has a natural pH of 4.0 to 6.0. Sodium Sulphite (Na2S03): Reagent grade sodium sulphite anhydrous of E.MERCK was used as oxygen scavenger. A solution of 25 - 50 ppm was prepared in 10,000 ppm NaCI solution. Sodium Chloride (NaCI): Reagent grade sodium chloride was used for preparing 1 % or 25% salt solutions. Calcium chloride (CaCI2): Calcium chloride of dihydrate grade was used. A solution of 0.1 - 1.0 % was prepared in fresh water. Isopropyl alcohol- propane-2-of AR assay 99.5% was used. A solution of 1500-3000 ppm was prepared in fresh water. Thiourea (H2NCSNH2) of AR assay 99% (iodometric) was used. A solution of 750-1500 ppm was prepared in fresh water. Formaldehyde: 0.5 - 3.0 % formaldehyde solution was used. Hydrochloric acid: N/10 solution was used for adjusting the pH in the range 2.5 7.0 whenever required. Water: Laboratory tap water was used for preparing and diluting all solutions. pH Meter: pH meter duly calibrated daily with standard buffer solutions was used for study. Magnetic stirrer: Magnetic stirrer was used for stirring the polymer solution. Oven: Roller Oven. Culture Tube: 10 ml culture tubes were used for aging the sample in the hot oven. Specially designed tubes and seals were used in aging cell for aging above 95°C. Gel scans were performed by mixing Bio polymer, cross linker, sodium sulphite, salt & other chemicals in a culture tube and placing the tube in a temperature controlled oven. The sample was visually inspected at 1 Hr, 3 Hrs and 24 Hrs to monitor the onset of gelation. For determining the quality of gel following gel ratings were used. 1 = Water like viscosity 2 = High-viscosity fluid 3 = Weak gel 4 = Elastic gel 5 = Stiff gel Once gelation had occurred, the samples were further aged at desired temperature to determine the stability of the gel with time. Field Application The Bio polymer Gel prepared by the process of this invention was tested at wells located in Rudrasagar field Upper Assam of Assam Asset in eastern India. The application was carried out in Brail Main Sand (BMS) of high permeability for relative permeability modification in wells with distinctive numbers as R-38, R-91 and R-114. Prior to application of process therein mentioned in Invention, all these wells were closed due to 100% water cut and no oil production as shown in Table 1. After the application of the biopolymer gel of process therein mentioned in Invention. The results post of process therein mentioned in Invention in R-38, R-91 and R-114 were producing oil with about 68%, 60% and 52% water cut respectively as shown in Table 2. These three treatments have generated about 11,000 Metric Tons (MT) of additional oil production. Analysis indicated that these jobs are a technical as well as an economic success. Evaluation of three Bio-polymer gel treatment jobs indicate the following: . All the three jobs are a technical success . All the three jobs are an economic success . Qil gain due to these jobs was estimated around 11000 Metric Tons Technology is simple and can be applied without a rig in wells on self-flow or on Gas Lift mode, and with a rig in wells on Electrical Submersible Pump (ESP) and Sucker Rod Pump (SRP) mode. TABLES Table 1: Pre-Job Test Data Well No \|Mode I QL(M3/D) I QO(M3/D) I W/C% R-38, R-91 & R-114 Well Closed Due To 100 % Water Cut. Table-2: Post Job Test Data Well No . R-38 Mode Gas Lift Gas Lift Gas Lift QL (M3jD) 43 32 30 QO(M3jD) 13.8 13' 14.4 WjC% 68 R-91 60 R-114 52 Abbreviations used in above tables are as: QL (M3/D) : It the quantity of liquid produced from a well in cubic meters in a span of 24 hrs termed as a day. Qo(M3/D) : It the quantity of Crude Oil produced from a well in cubic meters after deducting quantity of water separated out from QL (M3jD) in a span, of 24 hrs termed as a day. W/C % : It is units of water produced in volumetric basis along with oil but in 100 units of liquid produced in volumetric basis. It is defined in percentile numbers. ADVANTAGES: The relative permeability modifier gel system is applicable for oil sand products of any hardness due to salt content. This blocks the water production by relative permeability modification. This blocks the water from watered out wells. This can be used in limiting water in stripper and gravel packed wells. This gel requires no water source identification. This does not require deployment of work-over rig or a Coil Tubing unit. We Claim: 1. A process for preparing relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands comprising the steps of: a. admixing the xanthan gum solution of 1500-3000 ppm in brine solution of 10000 ppm and hydrating at least for one hour, b. adjusting the pH of the above admixture from 6.5 to 7 with the help of NaOH or HCI, c. adding sodium sulphite (Na2S0) solution of 25 to 50 ppm in NaCI Solution of 10,000 ppm for acting as a oxygen scavenger to the above prepared solution, d. adding 0.1 to 1% of Calcium chloride solution in fresh water, Isopropyl alcohol solution of 1500-3000 ppm in fresh water, Thiourea H2NCSNH2 solution of 750 to 1500 ppm in fresh water for acting as anti oxidant and 0.5 to 3% of Formaldehyde solution for acting as biocide to the above prepared solution, e. preparing Chromium Acetate ,the cross linking agent solution of 50 to 1000 ppm in NaCI Solution of 10,000 ppm and mixing the same with an aqueous polymer mixture to produce the gelation solution and the said solution is added to the admixture of step d to form relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands. 2. A process for preparing relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands substantially described as here in with reference to the example. Dated this 27th day of January 2003 M.P. MIRCHANDANI (Attorney for the Applicant)

Full Text

Original
FORM 2 THE PATENTS ACT, 1970
(39 of 1970) COMPELETE SPECIFICATION
[Section 10; rule 13]
A PROCESS FOR PREPARING RELATIVE PERMEABILITY MODIFIER BIO POLYMER GEL FOR BLOCKING / LIMITING WATER PRODUCTION IN OIL SANDS.
M/S. INSTITUTE OF OIL & GAS PRODUCTION TECHNOLOGY, OIL AND NATURAL GAS CORPORATION LIMITED, IOGPT Bldg., Panvel, NAVI MUMBAI- 410 221., Maharashtra, India.
17 JAN 2005
GRANTED
17-1-2005
The following specification particularly describes the nature of the invention and the manner

The invention relates to an improved chemical system of limiting water in oil sands by using a new relative permeability modifier gel system.
Petroleum liquids are stored underground in reservoirs. Wells are drilled to take out these petroleum liquids. Generally in reservoirs there are three types of fluids stored by nature i.e. gas, oil and water. Gases being the lightest are stored on top, oil in middle and water at the bottom in the reservoir sand. The production of unwanted water leads to both lifting and water disposal costs, add environmental concerns and reduces oil production. It also necessitates additional maintenance for production equipments and down hole treating for corrosion, bacteria, scale and naturally occurring radio-active material. The total handling and disposal cost of water is about 22 % of production cost.
To block the unwanted water from an oil well, the first step is to find out the exact source of water. There are many diagnostic methods to ascertain the source of water and their use also necessitate special well conditions. In the situation when water-producing zone is not known or when there is operating difficulties for diagnostic, chemicals methods can be used.
The best chemical available is cement. It can be used to shut the water around well bore with channels in isolating cement sheet between well and casing, where cement particle may enter or block the perforations. Micro-fine cement can be used to further improve the penetration of cement particle into the channels. Cement and micro-fine cement give temporary relief to some extent, but when there are repeated failures of cement squeezes, chemical methods can be used. The advantage associated with chemical & polymer methods is that they can be
designed and placed deeper into the reservoir and water may not be able to circumvent it easily and long lasting results are obtained.
There are several methods available to block the water from oil sands. The choice of methods depends on source of water and conditions prevailing in the oil sands. Also, the conventional gels cannot be used for restricting water production in all wells. This lead to an idea of use of relative permeability modifier gel system.
The present invention relates to an improvement in the design of chemical gel process. This

chemical process does not require identification of water source, isolation of zone and deployment of rig. It also doesn't seal the oil sand thereby stopping the production. This process during treatment does not cause damage to the oil wells. Present invention is a chemical process of relative permeability modifier consists of a polymer, cross-linker, salts, alcohol and aldehyde.
The present invention is described in the context of specific terms, which are defined as follows. The oil sand formation consists of a region where the formation volume is characterized as essentially homogeneous, continuous, 'sedimentary reservoir material. But this is inclusive of terms such as streaks, fractures, fracture networks, vugs, solution channels, caverns, washouts, cavities, etc.
The oil sand formation consists of horizontal "zones" of distinctive sub-ternean material of continuous geologic properties which extend in the horizontal direction. "Vertical conformance" is a measure of the degree of geologic uniformity in permeability as one moves vertically across the formation. "Areal conformance" is a measure of the degree of geologic uniformity in permeability as one moves horizontally across the formation. A "flow profile" qualitatively describes the uniformity of fluid flow through a subterranean formation while "sweep efficiency" the quantitative analog of "flow profile." "Plugging" is a substantial reduction in permeability in a region of a formation.
The term "gel" as used herein is directed to a continuous three-dimensional crosslinked polymeric network having an ultra high molecular weight. The gel contains a liquid medium such as water, which is confined within the solid polymeric network. The fusion of a liquid and a solid component into a single-phase system provides the gel with a unique phase behavior. Gels employed by the present invention have sufficient structure so as not to propagate from the confines of a plugged region into a less permeable region of the formation adjoining the plugged region once in place.
The gel is qualitatively defined as "flowing" or "non-flowing" based on its ability to flow under the force of gravity when unconfined on the surface at ambient atmospheric conditions. A flowing gel flows under these conditions; a non-flowing gel does not. Nonetheless, both a non-flowing gel and a flowing gel are defined herein as having sufficient

structure so as not to propagate from the confines of the desired treatment region when injected therein.
"Crosslinked to completion" means that the gel composition is incapable of further crosslinking because one or both of the required reactants in the initial solution are consumed. Further crosslinking is only possible if either polymer, crosslinking agent, or both are added to the gel composition.
The gel composition utilized in the present invention is comprised of Xanthan Gum a
commonly known as biopolymer having biological origin and a crosslinking agent capable of
crosslinking the two polymer species. The Biopolymer referred herein should be a free
flowing powder (free from lumps, dirt and foreign matter) with maximum of 15% moisture
content.
The biopolymer should be conformant to the rheological properties if tested as below:
Prepare 0.5% (W/V) solution of the biopolymer sample in distilled water containing 4%
(W/V) of sodium chloride (Laboratory Reagent Grade), by stirring with Hamilton Beach
mixer, at medium speed for 20 minutes. Adjust pH in the range of 8-9 by addition of IN,
NaOH solution while stirring. Determine the rheological properties of the suspension at 24+
2°C.
Results in:
(i) Apparent viscosity, CP -15-20
(ii) Gelo, lbs/100 sq.ft - 5 (min)
(iii)"n" value at 200 & 100 rpm- 0.4 (max)
The biopolymer should be conformant to the crosslinking properties if tested as below: Add 500 ml. of distilled water to 5 ml. of 3% (WjV) solution of calcium chloride (fused or LR grade) and to this solution, add 0.5%(WjV) of the sample, while stirring with Hamilton Beach mixer, at medium speed for 20 min. Add to it 0.2%(WjV) chrome alum powder (LR Grade) and stir further for 10 minutes. Adjust
pH in the range of 8-9 over a period of 20 minutes by slowly adding of IN, NaOH solution, while stirring at medium speed. Determine the rheological properties of the the suspension at 24+ 2° C. Results in:

Apparent viscosity, CPs -30 min Yield point Ibs/lOO sq.ft - 30 (min) Gelo, Ibs/lOO sq.ft -15 (min) Gel 10, Ibs/lOO sq.ft -30 (min)
The biopolymer should be conformant to the following performance test: Prepare 0.5%(W/V) solution of the sample in distilled water by stirring with Hamilton Beach mixer, at medium speed for 20 minutes. Adjust pH in the range of 8-9 by addition of iN, NaOH solution while stirring. Add 3%(W/V) of bentonite powder and stir further for 20 minutes. Determine rheological properties and API filtration loss. Transfer this mud to ageing cell and hot roll for 18 hrs. at 100+5° C.Cool to 24+ 2° C and determine rheological parameters and API filtration loss at 24+ 2° C. Change in parameters before and after hot rolling should be as under:
Apparent viscosity, CP - Shall not decrease Yield point, Ibs/lOO sq.ft - Shall not decrease API filtration loss, ml - Shall no increase
The biopolymer should be conformant to the following borate sensitivity test: Prepare 0.5% weight by volume (WjV) solution of the sample in distilled water by stirring with a mixer, at medium speed for 20 minutes. Add 5 ml. of 20%WjV of hot solution of borax and stir further for 5minur.es. Result should not form a stiff gel.
The crosslinking agent used in the present invention is chromium acetate. This compound includes one electropositive chromium III species and one electronegative acetate ion. Inorganic mono- and/or divalent ions, function merely to balance the electrical charge of the compound, or one or more water molecules may be associated.
According to this invention there is provided a process for preparing relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands comprising the steps of: a. admixing the xanthan gum solution of 1500-3000 ppm in brine solution of 10000 ppm

and hydrating at least for one hour,
b. adjusting the pH of the above admixture from 6.5 to 7 with the help of NaOH or HCI,
c. adding sodium sulphite Na2S03 solution of 25 to 50 ppm in NaCI Solution of 10,000 ppm
for acting as a oxygen scavenger to the above prepared solution,
d. adding 0.1 to 1% of Calcium chloride solution in fresh water, Isopropyl alcohol solution
of 1500-3000 ppm in fresh water, Thiourea H2NCSNH2 solution of 750 to 1500 ppm in fresh
water for acting as anti oxidant and 0.5 to 3% of Formaldehyde solution for acting as biocide to the above prepared solution,
e. preparing Chromium Acetate, the cross linking agent solution of 50 to 1000 ppm in NaCI
Solution of 10,000 ppm and mixing the same with an aqueous polymer mixture to
produce the gelation solution and the said solution is added to the admixture of step d to
form relative permeability modifier bio polymer gel for blocking/limiting water production in
oil sands.
Surface admixing broadly encompasses inter alia mixing the solution in bulk at the surface prior to injection or simultaneously mixing the solution at or near the wellhead by in-line mixing means while injecting it. Among other alternatives, the starting materials for the crosslinking agent can be dissolved directly in the aqueous polymer mixture to form the gelation solution in a single step but with continuous agitation.
The present process enables the practitioner to customize or tailor-make a gel having a predetermined gelation rate and predetermined gel properties of strength and stability from the above-described composition. The gelation rate is defined as the degree of gel formation as a function of time or, synonymously, the rate of crosslinking in the gelation solution. The degree of crosslinking may be quantified in terms of gel viscosity and/or strength. Gel strength of a non-flowing gel is defined as the coherence of the gel network or resistance to deformation under external forces. Gel strength of a flowing gel is defined as the resistance of the gel to filtration or flow. Stability is defined as either thermal or phase stability. Thermal stability is the ability of a gel to withstand temperature extremes without degradation. Phase stability is the ability of a gel to resist syneresis, which can detract from the gel structure and performance.

Present invention has temperature limit of the gelation solution at the surface is the freezing point of the solution and the upper limit is essentially the thermal stability limit of the polymer and or 105°C due to the additives. Thesolution is generally maintained at tropical ambient temperature at the surface. Increasing the temperature within the prescribed range at the surface increases the gelation rate and also, increasing the total polymer concentration increases the gelation rate and ultimate gel strength at a constant ratio of polymer to crosslinking agent.
The practitioner advantageously selects a predetermined gelation rate which enables preparation of the gelation solution at the surface, injection of the solution as a single uniform slug into the well bore, and displacement of the entire solution into the desired subterranean oil sand. Once in place in the desired treatment region, gelation of the solution advantageously proceeds to achieve substantially complete gelation of the solution in situ.
The present gelation mechanism enables the practitioner to design a gelation solution which can be injected into a treatment region at a desired injection rate
with little resistance to injectivity. The solution is preferably gelled once it is in place in the desired subterranean region to minimize lost production from shut in of the production wells. The gelation time of the gel ranges from near instantaneous for flowing gels up to 48 hours or longer for both flowing and non-flowing gels.
The present process is applicable to a number of hydrocarbon recovery applications. According to one embodiment, the process is applicable as sealant in case of oil sand permeability of 1 milli darcies to 25 milli darcies if placed selectively but the to the second embodiment the process is applicable as relative permeability modifier in case of oil sand permeability of 25 milli darcies and above wherein it shows the following behavior:
When this gel comes in contact with undesired water from the oil sand, which needs to be blocked causes swelling in the invented gel to offer maximum obstruction whereas when it comes in contact with oil, it acts as given in the point 2 below.
Also, under the same situation when oil comes in contact with the invented gel, gel shrinks and permits oil to flow preferentially as compared to the present water as given above.

In case of relative permeability modification, the solution can be bulldozed into entire high permeability zone of the oil sand formation and crosslinked to completion in-situ as either a non-flowing gel or a flowing gel. Both flowing and non-flowing gels can be used for treatment of high permeability zones of the matrix because in general neither will flow from the treatment zone upon complete gelation, a necessary condition for the present invention. However,non-flowing gels are often preferred for treatment of high permeability zones in direct communication with production wells because of their increased strength. The gels are produced in a manner, which renders them insensitive to most extreme formation conditions. The gels can be applied to the treatment of many different geological structures including high permeability zones within the formation oil sand. The gels can be stable at formation temperatures as high as 105°e. The gels are relatively insensitive to the stratigraphy of the rock and can be employed in carbonate and sandstone strata and unconsolidated or consolidated strata having varying mineralogy. Once the gels are in place, it is extremely difficult to displace the gels by physical or chemical means other than total destruction of the crosslinked network. The gels may be reversible on contact with hydrogen peroxide or sodium hypochlorite, but are substantially insoluble in the formation fluids.
The following examples demonstrate the laboratory test practice and utility of the present invention but are not to be construed as limiting the scope thereof.
Process Verification
The invention will now be described in more details with reference to its formulation to be
used in blocking the water from oil sands.
Laboratory Test Procedure
Polymer: Xanthan Polymer commonly termed as a Biopolymer due to its origin was used for
present study. A solution of 1500 - 3000 ppm was prepared in 10,000ppm NaCi solution.
Solution was allowed to hydrate for minimum one hour on a magnetic stirrer. The pH of
polymer solution was adjusted with NaOH or HCI.
Chromium (III) [Cr(CH3COO)3] : Reagent grade chromium acetate was used. A solution of
50 - 1000 ppm in 10,000-ppm salt solution was prepared. Fresh solution of chromic acetate has bluish color but after 24 hrs due to hydration its color changes to dark blue. Cr(III) acetate solution has a natural pH of 4.0 to 6.0. Sodium Sulphite (Na2S03): Reagent grade sodium sulphite anhydrous of E.MERCK was used

as oxygen scavenger. A solution of 25 - 50 ppm was prepared in 10,000 ppm NaCI solution.
Sodium Chloride (NaCI): Reagent grade sodium chloride was used for preparing 1 % or 25%
salt solutions.
Calcium chloride (CaCI2): Calcium chloride of dihydrate grade was used. A solution of 0.1 -
1.0 % was prepared in fresh water.
Isopropyl alcohol- propane-2-of AR assay 99.5% was used. A solution of 1500-3000 ppm
was prepared in fresh water.
Thiourea (H2NCSNH2) of AR assay 99% (iodometric) was used. A solution of 750-1500 ppm
was prepared in fresh water.
Formaldehyde: 0.5 - 3.0 % formaldehyde solution was used.
Hydrochloric acid: N/10 solution was used for adjusting the pH in the range 2.5 7.0
whenever required.
Water: Laboratory tap water was used for preparing and diluting all solutions.
pH Meter: pH meter duly calibrated daily with standard buffer solutions was used
for study.
Magnetic stirrer: Magnetic stirrer was used for stirring the polymer solution.
Oven: Roller Oven.
Culture Tube: 10 ml culture tubes were used for aging the sample in the hot oven. Specially
designed tubes and seals were used in aging cell for aging above 95°C.
Gel scans were performed by mixing Bio polymer, cross linker, sodium sulphite, salt & other
chemicals in a culture tube and placing the tube in a temperature controlled oven. The
sample was visually inspected at 1 Hr, 3 Hrs and 24 Hrs to
monitor the onset of gelation. For determining the quality of gel following gel ratings were
used.
1 = Water like viscosity
2 = High-viscosity fluid
3 = Weak gel

4 = Elastic gel
5 = Stiff gel
Once gelation had occurred, the samples were further aged at desired temperature to determine the stability of the gel with time.

Field Application
The Bio polymer Gel prepared by the process of this invention was tested at wells located in
Rudrasagar field Upper Assam of Assam Asset in eastern India. The application was carried
out in Brail Main Sand (BMS) of high permeability for relative permeability modification in
wells with distinctive numbers as R-38, R-91 and R-114. Prior to application of process
therein mentioned in Invention, all these wells were closed due to 100% water cut and no
oil production as shown in Table 1. After the application of the biopolymer gel of process
therein mentioned in Invention. The results post of process therein mentioned in Invention
in R-38, R-91
and R-114 were producing oil with about 68%, 60% and 52% water cut respectively as
shown in Table 2.
These three treatments have generated about 11,000 Metric Tons (MT) of additional oil
production.
Analysis indicated that these jobs are a technical as well as an economic success. Evaluation
of three Bio-polymer gel treatment jobs indicate the following:
. All the three jobs are a technical success
. All the three jobs are an economic success
. Qil gain due to these jobs was estimated around 11000 Metric Tons
Technology is simple and can be applied without a rig in wells on self-flow or on Gas Lift
mode, and with a rig in wells on Electrical Submersible Pump (ESP) and
Sucker Rod Pump (SRP) mode.
TABLES
Table 1: Pre-Job Test Data

Well No |Mode I QL(M3/D) I QO(M3/D) I W/C%
R-38, R-91 & R-114
Well Closed Due To 100 % Water Cut.
Table-2: Post Job Test Data

Well No . R-38 Mode Gas Lift Gas Lift Gas Lift QL (M3jD)
43
32
30 QO(M3jD) 13.8
13' 14.4 WjC% 68
R-91

60
R-114

52

Abbreviations used in above tables are as:
QL (M3/D) : It the quantity of liquid produced from a well in cubic meters in a span of 24 hrs termed as a day.
Qo(M3/D) : It the quantity of Crude Oil produced from a well in cubic meters after deducting quantity of water separated out from QL (M3jD) in a span, of 24 hrs termed as a day.
W/C % : It is units of water produced in volumetric basis along with oil but in 100 units of liquid produced in volumetric basis. It is defined in percentile numbers.
ADVANTAGES:
The relative permeability modifier gel system is applicable for oil sand products of any
hardness due to salt content.
This blocks the water production by relative permeability modification.
This blocks the water from watered out wells.
This can be used in limiting water in stripper and gravel packed wells.
This gel requires no water source identification.
This does not require deployment of work-over rig or a Coil Tubing unit.

We Claim:
1. A process for preparing relative permeability modifier bio polymer gel for blocking/limiting
water production in oil sands comprising the steps of:
a. admixing the xanthan gum solution of 1500-3000 ppm in brine solution of 10000 ppm and hydrating at least for one hour,
b. adjusting the pH of the above admixture from 6.5 to 7 with the help of NaOH or HCI,
c. adding sodium sulphite (Na2S0) solution of 25 to 50 ppm in NaCI Solution of 10,000 ppm for acting as a oxygen scavenger to the above prepared solution,
d. adding 0.1 to 1% of Calcium chloride solution in fresh water, Isopropyl alcohol solution
of 1500-3000 ppm in fresh water, Thiourea H2NCSNH2 solution of 750 to 1500 ppm in fresh
water for acting as anti oxidant and 0.5 to 3% of Formaldehyde solution for acting as biocide to the above prepared solution,
e. preparing Chromium Acetate ,the cross linking agent solution of 50 to 1000 ppm in NaCI
Solution of 10,000 ppm and mixing the same with an aqueous polymer mixture to
produce the gelation solution and the said solution is added to the admixture of step d to form relative permeability modifier bio polymer gel for blocking/limiting water production in oil sands.
2. A process for preparing relative permeability modifier bio polymer gel for blocking/limiting
water production in oil sands substantially described as here in with reference to the
example.
Dated this 27th day of January 2003

M.P. MIRCHANDANI (Attorney for the Applicant)

Documents:

98-mum-2003-cancelled pages(17-01-2005).pdf

98-mum-2003-claims(granted)-(17-01-2005).doc

98-mum-2003-claims(granted)-(17-01-2005).pdf

98-mum-2003-correspondence(17-01-2005).pdf

98-MUM-2003-CORRESPONDENCE(19-4-2010).pdf

98-MUM-2003-CORRESPONDENCE(27-11-2009).pdf

98-mum-2003-correspondence(ipo)-(08-07-2004).pdf

98-mum-2003-form 1(14-05-2004).pdf

98-mum-2003-form 1(27-01-2003).pdf

98-MUM-2003-FORM 15(27-11-2009).pdf

98-mum-2003-form 19 (19-09-2003).pdf

98-mum-2003-form 2(granted)-(17-01-2005).doc

98-mum-2003-form 2(granted)-(17-01-2005).pdf

98-mum-2003-form 3(27-01-2003).pdf

98-mum-2003-form 5(14-05-2004).pdf

98-mum-2003-other documents (27-01-2003).pdf

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Patent Number

198188

Indian Patent Application Number

98/MUM/2003

PG Journal Number

43/2008

Publication Date

24-Oct-2008

Grant Date

17-Jan-2006

Date of Filing

27-Jan-2003

Name of Patentee

M/S. INSTITUTE OF OIL & GAS PRODUCTION TECHNOLOGY

Applicant Address

OIL AND NATURAL GAS CARPORATION LIMITED, IOGPT BLDG,PANVEL, NEW BOMBAY-410 221, MAHARASHTRA, INDIA.

Inventors:

#	Inventor's Name	Inventor's Address
1	BANSH NARAIN YADAV	D-17, ONGC RESIDENTIAL COMPLEX, PANVEL, NAVI MUMBAI-410221, Maharashtra, India.
2	MR. RANJEET KUMAR ANAND	FLAT NO 1003-B, RAVAL TOWER, PLOT NO 10, SECTOR 11, CBD BELAPUR, NAVI MUMBAI-400614.
3	MR. SATISH BEHARILAL BHATNAGAR	FLAT NO 304-305, CITI AVENUE, PLOT NO 101, SECTOR 1-S, NEW PANVEL, NAVI MUMBAI-410206.

PCT International Classification Number

N/A

PCT International Application Number

N/A

PCT International Filing date

PCT Conventions:

#	PCT Application Number	Date of Convention	Priority Country
1			NA