Shale stabilizing drilling fluids comprising calcium chloride and low molecular weight low charge cationicpolyacrylamide copolymers

This application claims priority from provisional application No. 60/102,729 filed Oct. 1, 1998.

The present invention relates to drilling, drill-in, and completion fluids, preferably water-base fluids, with good shale encapsulation properties resulting from the presence of calcium chloride and a low molecular weight, low charge cationic polyacrylamide copolymer.

Fluids used during drilling operations include “drilling,” “drill-in,” and “completion” fluids. A “drill-in” fluid is pumped through the drill pipe while drilling through the “payzone,” or the zone believed to hold recoverable oil or gas. A “drilling fluid” is used to drill a borehole through the earth to reach the payzone. Typically a drilling mud is circulated down through the drill pipe, out the drill bit, and back up to the surface through the annulus between the drill pipe and the borehole wall. The drilling fluid has a number of purposes, including cooling and lubricating the bit, carrying the cuttings from the hole to the surface, and exerting a hydrostatic pressure against the borehole wall to prevent the flow of fluids from the surrounding formation into the borehole. A “completion fluid” is used to protect the “payzone” during the completion phase of the well.

Fluids in which water is the continuous phase provide for a fast drilling rate, and are ecologically favored over fluids in which oil is the continuous phase. Unfortunately, the walls of a wellbore frequently are composed at least in part of shale, and when exposed to water, many shales swell, slough, or spall to the extent that they may even prevent further operation of the wellbore. Shale also may slough off during gravel transport in open-hole completion, mix with the gravel, and reduce the productivity of the well by choking off the permeability of the gravel pack. The sloughing also may cause screen blinding.

Brines have long been used in the formulation of drilling fluids to take advantage of their density and their inhibitive characteristics. Clay chemistry has shown us that cationic base exchange with the negatively charged clay minerals commonly found in shale formations, limits their ability to hydrate, soften, and swell, thereby rendering them more stable in the presence of water based fluids.

Monovalent salts, such as NaCl or KCl, have long been used as make up water for drilling fluids. In the past, NaCl or KCl have provided a limited inhibitive environment for drilling hydratable shales in many areas. In offshore drilling, seawater—a complex mixture of various salts which is readily available—has frequently been used in formulating drilling mud.

Today, technological advances in the design of drilling equipment has resulted in increased penetration rates for better drilling economics. The performance of the monovalent salt systems has not been able to maintain pace with new advances in drilling technology. The need for improved drilling mud systems saw the application of oil mud systems and development of synthetic systems to meet these challenges. However, increasing environmental regulation has limited the application of these systems.

Divalent salts are known to provide an added inhibitive benefit for drilling water sensitive shales. Divalent salts are capable of developing a strong bond with and between active clay platelets in these shales, thereby further limiting the volume of hydration water that can become a part of the clay, causing it to become soft, pliable, and sticky, resulting in problems with mechanical drilling equipment and drilling fluid control. One of the most available and economical divalent salt systems is CaCl 2 . CaCl 2 systems have been around for many years, and the inhibitive characteristics of the calcium ion are well known.

Water-soluble polymers are used to thicken water-base fluids, and in part to synergistically stabilize shale. The water-soluble polymers provide the viscosity necessary to lift drilled solids from the wellbore, and tend to improve drilling rates.

Unfortunately, fluids which have shown promise in increasing the rate of penetration through shales also have tended to increase screen blinding, which can lead to huge losses of mud, with loss of rig time and high fluid costs. Water base fluids are needed which can achieve a high rate of penetration without screen blinding.

The present invention provides a drilling system fluid comprising water as a continuous phase, a first amount of a divalent metal salt, and a quantity of a polyacrylamide copolymer, wherein the amount of the divalent salt and the quantity of polyacrylamide copolymer are sufficient to produce a rate of penetration approaching that achieved using a synthetic oil-based drilling system fluid while preventing substantial screen blinding. In a preferred embodiment, the continuous phase also comprises a second amount of a monovalent salt effective to increase gas hydrate suppression and decrease density when compared to a fluid consisting essentially of only a divalent salt in the absence of the monovalent salt.

The present invention involves formulating aqueous-base drilling fluids to stabilize shale encountered during drilling. The water base fluids of the present invention comprise a combination of a suitable divalent salt, a suitable monovalent salt and a relatively low charge cationic, low molecular weight polyacrylamide copolymer. In a preferred embodiment, the divalent salt is calcium chloride and the monovalent salt is sodium chloride. This fluid composition provides a rate of penetration that approaches synthetic oil-based systems, and also provides good shale encapsulating properties for control of gumbo shale without substantial screen blinding. For purposes of the present application, the term “substantial screen blinding” is defined as the formation of a mat of undissolved or dispersed polymer on the shaker screen, which blocks passage of the hole fluid through the shaker screen, causing the hole fluid to overflow the shaker screen.

The polyacrylamide copolymers of the present invention may be used in substantially any drilling, drill-in, or completion fluid. As used herein, the term “drilling fluid” or “drilling fluids” shall be interpreted to refer to any one of these kinds of fluids. Preferred drilling fluids have water as a continuous phase.

Preferred drilling fluids comprise a mixture of salts consisting of brines comprising about 5 wt % to about 20 wt %, preferably about 15 wt % of the divalent salt, most preferably calcium chloride and about 0 lb/bbl to about 70 lb/bbl, preferably about 40 lb/bbl to about 70 lb/bbl, most preferably 50 lb/bbl of the monovalent salt, preferably sodium chloride. The fluids can contain substantially any suitable salts, suitable divalent salts include, but are not necessarily limited to salts based on metals, such as calcium, magnesium, zinc, and aluminum. Suitable monovalent salts include but are not necessarily limited to those based on metals such as sodium, potassium, cesium, and lithium. The salt may contain substantially any anions, with preferred anions including, but not necessarily limited to chlorides, bromides, formates, propionates, sulfates, acetates, carbonates, and nitrates. A preferred anion is chlorine. Preferred brines comprise calcium chloride. Sodium chloride is typically added to the drilling fluid after the calcium chloride brine.

The water-base drilling fluids contain “water-soluble polymers,” defined as polymers that are capable of viscosifying a drilling fluid and/or providing filtration control for a drilling fluid. Preferred viscosifiers and filtration control agents are XAN-PLEX™ D, BIO-PAQ™ and/or BIOLOSE™, all of which are commercially available from Baker Hughes INTEQ.

The drilling fluids of the present invention also contain “polyacrylamide copolymers” to provide shale inhibition. The term “polyacrylamide copolymers” is defined herein to refer to cationic polyacrylamide copolymers having a relatively low molecular weight and a relatively low charge. The term “low molecular weight” is defined to mean copolymer units having from about 500,000 to 4 million mole weight, preferably from about 800,000 to about 1 million mole weight. The term “low charge” is defined to mean from about 1 mol % to about 15 mol % of a cationic monomer charge, preferably about 5 mol % to about 10 mol % cationic monomer charge. The cationic monomer charge may be from about 1 to about 4. Without limiting the present invention to a particular mechanism of action, it is believed that cations in the polyacrylamide copolymer adsorb onto the negatively charged surface of the shale, forming a gelatinous protective layer which inhibits degradation of the shale.

Suitable polyacrylamide copolymers have the following general structure:

wherein R and R 1 are selected from the group consisting of hydrogen, acrylamide groups, acrylate groups, polyacrylamide groups, and polyacrylate groups, and copolymers thereof; R 2 is selected from the group consisting individually of hydrogen, and alkyl groups, preferably methyl and ethyl groups; and, R 3 is selected from the group consisting of ester groups comprising a cationic group and amide groups comprising at least one cationic group, wherein said cationic group comprises a charge in the range of from about +1 to about +4; and, n is at least 1. A preferred cationic group has the following general structure:

Suitable polyacrylamide copolymers are commercially available from a number of sources, and include but are not necessarily limited to HYPERDRILL CP-904L™, available from Hychem, Inc., Tampa, Fla., and SUPERFLOC™, available from Cytec Industries, West Patterson, N.J. A preferred polyacrylamide copolymer is DFE-243, which comprises partially hydrolyzed polyacrylamide (PHPA) and trimethylaminoethyl acrylate, which has about a 800,000 to 1 million molecular weight and about a 5% to about a 10% cationic charge density. DFE-243 is commercially available from Baker Hughes INTEQ.

In order to achieve the desired shale stabilization, the fluid should contain from about 0.05 wt % to about 0.5 wt % of the polyacrylamide copolymer, preferably at least about 0.08 wt %, most preferably at least about 0.3 wt %,of the polyacrylamide copolymer.

Bridging or weighting agents preferably should be added to bridge the pores in the formation. Suitable bridging or weighting agents include, but are not necessarily limited to ground marble or calcium carbonate particles, such as MIL-CARB, available from Baker Hughes INTEQ. Preferred calcium carbonate particles have a mean particle size of about 30 microns. Calcium carbonate has the advantage that it is acid soluble, and therefore can be removed from the formation by acid flushing. If calcium carbonate is used as the bridging agent, then from about 10 to about 50 pounds should be used per barrel of brine.

Preferred polyacrylamide copolymer containing drilling fluids are “non-toxic.” As used herein, the term “non-toxic” is defined to mean that a material meets the applicable EPA requirements for discharge into U.S. waters. Currently, a drilling fluid must have an LC 50 (lethal concentration where 50% of the organisms are killed) of 30,000 parts per million (ppm) suspended particulate phase (SPP) or higher to meet the EPA standards. The mysid shrimp toxicity test for a drilling fluid according to the present invention containing 1.0-1.25 lb/bbl DICAP™ resulted in an LC 50 of 120,000 ppm of the suspended particulate phase (SPP)—4 times the minimum EPA standard for discharge into coastal waters. The toxicity tests for the 0.1-1.5 lb/bbl DFE-243 resulted in an LC 50 of 150,000-300,000 ppm of the SPP.

In order to prepare the foregoing drilling fluids, fresh water is placed in a mixing hopper and the following are added: the viscosifying polymer (XAN-PLEX™ D, available from Baker Hughes, INTEQ), and the filtration control polymer (BIO-PAQ™ and/or BIOLOSE™, also available from Baker Hughes INTEQ). The mixture is agitated well before adding the calcium chloride brine and the sodium chloride. XAN-PLEX™ D and the polyacrylamide copolymer should not be added at the same time. A preferred mixer to prevent “fish-eyeing” of the polymers is a shear device similar to Gauthier's Brothers, POLYGATOR GBR. The mixing equipment should be capable of very good agitation at high shear to disperse all of the ingredients—particularly the polymeric ingredients—to achieve a final smooth blend. Preferably, the mixing hopper should be in-line so the sheared polymer goes directly into the mixing tank as opposed to using a low shear hopper and then “re-circulating” through the high shear device. The mixing pits also should have an impeller for proper mixing and dispersion of the polymers.

Preferably, calcium chloride or a 15 wt % calcium chloride brine is added to the mixture first, then NaCl is added to the mixture. After sufficient agitation, the polyacrylamide copolymer is sifted into the mixture with good agitation. After sufficient agitation, MIL-CARB™, MIL-BAR™, and any other additives, such as gas hydrate suppressors, are added to the mixture with agitation, as needed. To minimize sag of MIL-CARB™ and MIL-BAR™ during storage or transport, 3 lb/bbl of SALT WATER GEL® may be added and sheared well before transferring the fluid to the mixing pit. Before measuring the pH of the mud, the mud should be diluted in a ratio of 9 parts deionized water to 1 part mud and thoroughly mixed.

If cement is to be drilled using the fluid of the invention, the fluid should be protected from cement contamination. In order to prevent cement contamination, the acidic pretreatment product is added before any green cement (MIL-CARB™ or MIL-BAR™) is incorporated into the system to prevent pH effects on the biopolymer or filtration control agent. Citric acid powder (to reduce pH to ±7) is recommended as a pretreatment product and can be used more safely than commonly used liquid acetic acid to control mud pH while drilling cement.

As much “quality” premix mud should be prepared at the mixing plant as possible so that the mud engineers on the rig can keep up with mud volume requirements of large diameter/high rate of penetration drilling operations. Otherwise, the polymers may be poorly dispersed, resulting in severe “fish-eyeing” and resultant screening problems.

The invention also is directed to a method for increasing shale stability of a drilling fluid containing the claimed brine by mixing a polyacrylamide copolymer with the brine, either before using the brine to formulate a drilling fluid, or during operation as an additive to the drilling fluid. If the polyacrylamide copolymer is used as an additive, an amount of copolymer preferably is added in increments of about 0.25 lb/bbl in order to achieve a surplus of polyacrylamide polymer in the filtrate of about 0.3 to about 1.0 lb/bbl.

The invention will be more clearly understood with reference to the following examples, which are illustrative only and should not be construed as limiting the present invention. In the following Examples, the following materials are trademarked products available from Baker Hughes INTEQ: XAN-PLEX™ D; DICAP™; MIL-BAR™; MIL-CARB™; BIO-PAQ™; and BIOLOSE™. REV-DUST™ is a trademark for a product which may be obtained from Mil-White Company, Houston, Tex. “Encapsulator D” is a commercially available shale inhibitor used for comparative purposes.

Early laboratory investigations centered around the evaluation of primary viscosifiers for the proposed fluid. Further laboratory testing included an evaluation of XAN-VIS (clarified xanthan gum with greater calcium tolerance) vs. XAN-PLEX™ D polymer. Shale inhibition tests used shale wafers constructed from GOM “gumbo” and a pelletized bentonite product, “Hole Plug”. Additional testing included an examination of the addition of cement treatment additives to prevent the detrimental effects of increased pH on the solubility or cross-linking of biopolymers.

The following laboratory equipment was used in conducting the experiments described in the examples:

Mixer: Prince-Castle equipped with FANN B-7210 Blade or equivalent (3.0 mm (0.5±mm pitch)

Baffled, 2 liter, stainless conical mixing cups (Prototypes) from INTEQ-Houston Fluids

Mixer: Waring Blender with standard blade and mixing cup

Tachometer: hand held Model CT800 described in the RS Components Catalog or equivalent

Mixing Cup: 1 or 2 liter, conical cups, OFI Model 110-50 or equivalent

Balance: precision of 0.01 g (2000 g capacity)

Thermometer: precision of ±1° F. or ±0.5° C.

Thermometer-metal 1¾″ dial, 8″ stem Cole Palmer H08080-04 precision ±1% of dial range

Motor-Driven Direct Indicating Viscometer as referenced in API RP 13-B-1, 1 st Edition, June 1990, Par. 2.4

Filter Press as referenced in API RP 13B-1, 1 st Edition, June 1990, section 3.2

Filter Press as referenced in API RP 13B-1, 1 st Edition, June 1990, section 3.4

Aging Cells as referenced in API Recommended Practice 13-I, 5 th Edition, Jun. 1, 1995, section 19

Oven: regulated to desired temperature ±5° F. (±3° C.). Preferred ovens are digitally controlled with 1) dynamic air circulation, 2) temperature recorders and 3) data acquisition system

Glass jars for aging at temperatures <160° F. (450 ml capacity)

The following mixing procedures were used in the following examples:

1. Mixer: Prince-Castle with FANN B7210 or equivalent blade

2. Mixing volume: 2 laboratory barrels (700 mls)

3. Total mixing time: 1 hour

4. Mixing speed: 9000 rpm

5. Mixing Temperature: Ambient to 150° F.

6. Order of addition: An important element of all laboratory testing included a product order of addition and mixing times required for complete product dispersion and/or solubility. The following describes the order of addition, and the mixing time for each product used in testing the formulations:

Component/Time, min/Product

Water/0 min/liquid phase

Viscosifier/10 min/XAN-PLEX D

Fluid Loss Control/10 min/BIO-LOSE™

11.6 lb/gal CaCl 2 brine/1 min/liquid phase

Shale Stabilizer/30 min/DFE-241/242, Encapsulator D

Bridging material/5min/MIL-CARB

Contaminant/4 min/Rev Dust, cement

Notes

XAN-PLEX™ D was selected as the most cost effective viscosifier. Both Kelco XCD and XAN-PLEX™ D were used in all other tests.

Baffled mixing cups will reduce spillage and increase shear.

If mixing time for total product additions is less than the total mixing time, continue mixing fluid after the last product addition until the total mixing time has been reached.

After heat aging, mix fluid at 6000 rpm for 5 minutes prior to testing.

Use defoamer as necessary.

Inhibition tests included both the Hole-Plug and “gumbo wafer” tests.

Throughout the first series of tests (Examples I-VIII), emphasis was placed on the performance of a 9.6-9.8 lb/gal CaCl 2 fluid; however, a limited number of tests were performed with a 12 lb/gal fluid to establish some continuity effect of the various additives. The calcium chloride content was maintained at 17 wt %. No change in recommended mixing procedures nor treatments were determined for the heavier fluid.

Quantitative data was difficult to obtain using laboratory screening tests. Some trends of screening efficiency could be seen. Three approaches were taken to quantify screening times. In each test, the time (in seconds) required for the majority of a fluid to pass through a screen or sieve under given conditions was measured. The cut-off time was based on visual retention on screen.

In the first test, 350 cm 3 of fluid was poured over an 8″ sieve while hand held over a vibrator. In another test, a small 3″ sonic sifter was briefly evaluated. In a third test, a mechanical shaker was constructed and used in making the measurements.

Effect of shear history and order of addition were considered in the screening series. Lower Prince Castle speeds, pre-dispersed xanthan gum and other shear devices including a Hamilton Beach Blender was part of the overall evaluation process.

Based on the results of these initial screening tests, a number of candidate fluids were selected for full scale screening.

A full scale screen test was performed to evaluate the results of the laboratory study. This test was conducted on a Brandt Shale Shaker. Tests were made using 150 barrels of 9.7 lb/gal calcium chloride fluid as sheared by liquid mixing equipment and after high shear through a Gauthier Polygator device. The Gauthier Polygator device was found to do a superior job in the blending of fluid components, particularly when using the biopolymers. Screen sizes tested were 50's and 24's at an ambient temperature of 65-70° F., and flow rates of 250 gal/min, the maximum capacity that the return line could handle. The tested fluids did not exhibit screen blinding.

The results of all laboratory testing led to the development of a standard test fluid for an initial series of testing and screening of products. This formulation is described in the following Table:

Further tests were conducted using a fluid having the foregoing composition. Testing concerned with the effects of static and hot roll aging on shale wafers and Hole Plug bentonite pellets. For these tests, an encapsulator was added at a 1 lb/bbl concentration to the base fluid. The results of these tests are outlined in the following Table. There was only a small change in the hardness of the shale wafer with 100% recovery. In the case of the Hole Plug, there was an 89.3% recovery after aging.

Tests continued using a similar 17% CaCl 2 base mud with other encapsulating additives to determine the product yielding the most benefit from the standpoint of shale inhibition and screening times. The following results were seen:

The encapsulating polymers provided good recovery, hardness and volume change in the test specimens with DICAP™ providing the best results for the shale wafer tests in hardness change.

A test series was performed to study the effects of shear (high vs. low) and mixing time after the addition of the various components and the ability to screen these muds through a fine mesh shaker screen. The systems were mixed using two different mixing devices; a Prince Castle mixer with controllable rpm to represent the results obtained from low shear mixing, and a Waring Blender for high shear mixing. The following Table tabulates the results of these tests.

The high shear in the first case considerably extended the amount of time required to screen the sample. This could be attributed to the incorporation of air into the sample, giving it a “fluffy” texture, or the additional mixing time on the polymer fluid loss control product or the encapsulator. In the case of the low shear mixing tests, mixing time is a significant factor in the ability to screen the sample.

Following further laboratory tests and the full scale liquid mud plant investigation, the opportunity for an on site test at an offshore drilling location presented itself. A major operator had previously drilled three prior offset wells in deepwater offshore Gulf of Mexico (“GOM”). Two of the three wells employed a CaCl 2 fluid and the third drilled with a NaCl/PHPA fluid. In the three wells, it required an average of 1-½ additional drilling days because of severe screen blinding. Blinded screens had to be constantly changed which required an interruption of the drilling operation. Associated mud solids build-up contributed to this problem.

The available rig mixing equipment was not satisfactory for proper dispersion of polymer products mixed on location. Polymer “fish eyes” were observed being discarded as well as contributing to the “blinding” of the shaker screens. This further points to the need for better rig mixing equipment and/or product enriched, properly blended muds for volume building being mixed onshore and transported to the rig site. The correct land based mixing equipment does not preclude the need for similar rig equipment, as it is not always practical to mix all systems at a shore based operation.

A deepwater CaCl 2 system was developed and field tested in the GOM. The CaCl 2 /DICAP™ system proved successful in controlling the gumbo without severe screen blinding. Instantaneous drill rates up to 200 ft/hr were experienced during the drilling of the gumbo section Drilling days and cost per foot for this section were substantially reduced. Estimated savings was four drilling days, or approximately $800,000 in rig costs.

In summary, the enhanced encapsulation of the CaCl 2 /DICAP™ mud system increased ROP, improved solids removal efficiency, and reduced overall interval drilling cost through the gumbo section.

Additional laboratory work was performed to determine the best formulation for a calcium chloride only base polyacrylamide copolymer to be used in the drilling fluid. The polyacrylamide copolymer used in the foregoing experiments was DFE 241, a relatively high molecular weight version of DICAP™ (with about 6,000,000 mole weight). Laboratory testing found that a lower mole weight version polyacrylamide copolymer, with about 4,000,000 mole weight, was more effective.

Numerous laboratory tests were conducted to evaluate the benefits of an encapsulator-in CaCl 2 fluids. Results were compared using an untreated CaCl 2 base fluid against one treated with DICAP™ and another with Encapsulator D. No pH adjustments were made in this test series. This data is reported in the following Table. It will be noted that DICAP™ gave a significantly greater percentage of sample recovery after aging the samples dynamically for 40 hours at 100° F. and 150° F. aging temperatures.

In these and other tests using Hole Plug bentonite pellets, varying degrees of solids recovery were noted following aging in different brine/polymer mixtures. The sample aged in 20% CaCl2 containing one (1) pound per barrel DICAP™ exhibited the least deterioration of any other salt/polymer combination.

Additional studies were done using a mixture of sodium chloride and calcium chloride. The calcium chloride content was varied from 14 to 17 wt %. The following basic formulation was used in the tests:

The above formulation was tested at varying densities. The results of the tests are listed in the following Table:

The addition of a mixture of salts including sodium chloride aided in gas hydrate suppression as well as density control. The polyacrylamide DFE-243 has a low molecular weight of from about 800,000 to 1 million mole weight and has about a 5% cationic charge, which improved the API and HTHP filtration results and lowered the coagulation of low gravity solids. Colloid stabilizers DFE520/521, available from Baker Hughes INTEQ, were used to offset the degree of coagulation and provide extra filter control.

Many modifications may be made to the present invention without departing from the spirit and scope of the present invention. The embodiment described herein is meant to be illustrative only and should not be taken as limiting the invention, which is defined in the following claims.