GB2152552A - Process for drilling a well - Google Patents

Abstract

A process for drilling a well in an underground formation in which process a drilling fluid is circulated in said well. The drilling fluid contains a hetero polysaccharide which has been obtained by cultivation of Pseudomonas sp. NCIB 11592. By this process a better efficiency is obtained.

Description

SPECIFICATION Process for drilling a well The invention relates to a process for drilling a well in an underground formation in which process a drilling fluid is circulated in said well, while drilling, characterized in that the drilling fluid contains a heteropolysaccharide which has been obtained by cultivation of Pseudomonas sp. NCIB 11592.

When drilling subterranean wells such as, for example, oil or gas wells, the rotary drilling method is commonly employed. The rotary drilling method utilizes a bit attached to a drill stem, and a drilling fluid or "mud" which is circulated through the drill stem to the bottom of the borehole where it is ejected through small openings in the drill bit. The fluid is then returned to the surface through the annular space between the drill stem and the borehole wall, or casing if one has been installed. Upon reaching the surface, the drilling fluid or "mud" is ordinarily treated to remove cuttings obtained from the borehole, and is then recirculated.

Drilling fluids serve many functions, and should therefore possess a number of desirable physical and rheological properties. For example, the viscosity of a drilling fluid should be sufficient to permit it to effectively transport bit cuttings from the bottom of the borehole to the surface for removal. A drilling fluid should also prevent excessive amounts of fluid from flowing from the borehole into surrounding formations by depositing on the wall of the hole a thin but substantially impervious filter cake. In addition, a drilling fluid should be able to hold solids in suspension, preventing their return to the bottom of the hole when the circulation is reduced or temporarily interrupted. This property can be obtained by utilizing additives which will impart a gel structure to the drilling fluid to increase viscosities.The gel structure, however, is preferably such that cuttings can be removed from the drilling fluid by passing the fluid through filtration equipment such as a shale shaker and/or sand cyclones prior to recirculating the fluid to the drill bit. A drilling fluid must also exert pressure on the surrounding formations, thus preventing possible collapse of the borehole or influx of highly pressurized oil or gas in the formation. Finally, a drilling fluid should serve as a lubricating and cooling agentforthe drill string.

Traditionally, bentonite or other clay solids have been utilized to increase the viscosity of the drilling fluid.

Today however, there is a growing belief that bentonite or clay suspensions have serious limitations as a drilling fluid base. The rheology of bentonite-based fluids in such that the hydraulic horsepower delivered to the bit at a given surface pressure is significantly less than with drilling fluids containing polymers. The lowervisocisty and/or solids content of these polymer muds result in a faster bit penetration rate which in turn decreases the drilling costs.Those working within the industry have attempted to substitute for the clay solids of the older muds by various polymeric materials including, for example: cellulose compounds such as carboxyethyl cellulose, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, hydroxyalkyl celluloses, alkyhydroxyalkyl celluloses, alkyl cellyloses, and alkylcarboxyalkyl cellyloses; polyacrylamides; natural galactomannans such as guar gum, locust bean gum, and gums derived from endosperm seeds; and various other polysaccharides.

In addition to the drilling fluids employed in drilling subterranean wells, it is known throughout the industry that other fluids can also be utilized for certain specialized applications. For example, fracturing fluids, spacing fluids, plugging fluids, cementing fluids, and completion fluids may be utilized in addition to a drilling fluid to achieve a particular result at one stage or another in the drilling operation. It is recognized by those of ordinary skill in the art, however, that compositions exhibiting properties desirable for some specialized application may not perform satisfactorily where employed for another purpose. Unlike fracturing fluids, drilling fluids are recirculated through the well many times.Although much of the larger particulate matter, such as bit cuttings, is removed from the drilling fluid after each cycle through the well, the fine solids content of the fluid becomes progressively greater with continued circulation. Where the drilling fluid comprises a heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592, it has been found that it tends to encapsulate the drilled solids suspended in the fluid. This encapsulating characteristic prevents disintegration of drilled solids and so improves the effectiveness of the drilling fluid, and is considered very desirable.

Notwithstanding the advances made in drilling fluid technology in recent years, there remains a need for a suitable fluid that will significantly improve bit penetration (and hence the drilling rate), will remain shear stable even after being recirculated through the borehole many times, will reduce the pressure losses due to friction in the drill pipe, will promote better lifting and therefore less grinding of cuttings at the bottom of the borehole, will maintain borehole cuttings in a suspended state during drilling interruptions, and will encapsulate the drilled solids suspended in the drilling fluid.

The drilling fluid used according to the invention has these beneficial properties.

The invention resides in a process for drilling a borehole utilizing a rotating drill bit, wherein a drilling fluid is circulated past the surface of the drill bit, comprising employing as the drilling fluid the aqueous liquid of a heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592. The drilling fluid is made by admixing the heteropolysaccharide with water, circulating the admixture thus formed for a period effective to permit hydration of the polymer. The heteropolysaccharide is disclosed by European patent application No.

81200479.4 (Publication No.0040445). The composition disclosed herein will exhibit extremely desirable physical and rheological properties, including improved flow characteristics as well as increased shear stability over a prolonged period of use.

The drilling fluid of the subject invention is preferably made at the use site by slowly adding a heteropolysaccharide solution or emulsion to water circulating through conventional blending equipment such as a jet hopper, and into the mud pit. The water employed is suitably as fresh as is reasonably obtainable, although brines may equally well be employed and may be preferabie where shale sloughing or formations with a high clay content are expected to be encountered. This versatility is another advantage of the drilling fluid of the present invention. When all the polymer has been added, the fluid can be applied without extra circulation since hydration of the heteropolysaccharide was already substantially complete. An effective amount of a suitable buffer may be added if desired to promote hydration, as will be understood by those skilled in the art.

The unweighted drilling fluid thus formed preferably comprises from 0.1 to 10 kg polymer per m3 of fluid.

Most preferably the unweighted drilling fluid comprises from 1 to 5 kg polymer per m3. If desired, the viscosity of the drilling fluid may be increased at a point in time subsequent to the initial preparation of the drilling fluid by gradual addition of more polymer and/or crosslinker.

Biopolymers are widely used in drilling, completion and workover fluids. Aqueous solutions containing the biopolymers have pronounced pseudoplastic rheological characteristics which give them high carrying capacities at low shearicirculation rates. Unfortunately, they often cannot be effectively acid-degraded and are, therefore a potential source of formation impairment. It has now been found that the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592 is very well acid-degradable e.g. it degrades within an hour in the presence of a 10 /O HCI solution.

Rheological measurements on solutions of the present heteropolysaccharide show that it is an effective viscosifier up to 55 "C in fresh water and up to at least 70 C in concentrated brines. The plot of viscosity against temperature is reversible in the sense that identical plots are obtained by increasing or decreasing temperature. Moreover this heteropolysaccharide is a very powerful viscosifier and at low shear rate, it has an excellent carrying capacity.

Hot-rolling tests are conducted to measure the shear and temperature degradation of the present heteropolysaccharide. A sodium chloride brine viscosified by this heteropolysaccharide is hot rolled for 18 hours at 80 "C, and its viscosity is measured at 21 C before and after rolling. No reduction in viscosity is found. This confirms the high shear stability of the present heteropolysaccharide. A calcium chloride based drilling fluid containing HEC (hydroxyethyl cellulose), the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592 and calcium carbonate were formulated and used to drill the production hole of an oil well in the Norwegian Troll field. No mud engineering problems occured and production tests showed the well to be highly unimpaired.

In addition the productivity of the well far exceeded the productivities of the previous ten wells drilled in the field using other mud systems.

As mentioned hereinbefore drilling fluids may contain many different substances. The drilling fluid to be used in the process according to the invention preferably contains in addition to the heteropolyaccharide obtained from Pseudomonas sp NCIB 11592, at least one fluid loss additive, at least one thinner, at least one weighting agent and or at least one salt.

Especially preferred examples of these materials are bentonite, baryte, one or more other polymers, one or more starches, one or more lignosulphonates, gypsum, dolomite andior lye. The content of the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592 in the drilling fluid to be used in the present process may vary within wide ranges. Preferably this drilling contains from 0.1 to 10 kg of the heteropolysaccharide per 1000 kg of fluid.

The invention will now be further elucidated by means of the following example to which it is by no means restricted.

Example Both cutting encapsulating and triaxial shale tests (cf. Darley, H. C. H., "A laboratory Investigation of borehole stability". J. Pet. Tech., July 1969,883-893, Trans. AIME, 246) were carried out on the relatively water sensitive Pierre shale. In the cutting encapsulation tests, a set amount of Pierre shale cuttings of a specific size distribution (1.7-3.4 mm) was added to a base mud containing the test polymer. Mud and shale cuttings were hot rolled for either 2 or 16 hours at 60 CC. and the percentage of shale cuttings still having the original size distribution measured. This percentage is termed the "recovery". Composition and properties of the base mud are given in Table 1.

In the standard triaxial shale test, a 50 mm diameter 25 mm long cylindrical reconstituted shale sample with a 6 mm diameter axial hole through it is put under a confining stress and mud is circulated through the hole at a specific rate. When the sample has coilapsed due to erosion or the axial hole has closed due to swelling the test is stopped. The time and mode of failure are recorded and erosion and water content of the samples measured. The mud compositions, mud properties and test conditions pertaining to these tests are given in Table 2. In essence, the tests compared the performance of a mud containing hydrolysed polyacrylamide (PAA) and a mud in which the hydrolysed polyacrylamide (PAA) was replaced by the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592.

The results of the cutting encapsulation tests are given in Table 3. They show that the encapsulating properties of the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592 are excellent. It is worth noting that these biopolymers achieved good encapsulating properties without incurring excessive plastic viscosities.

The results of the triaxial tests are given in Table 4. At first sight, the performance of the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592 is far superior to that of the PAA, however, this requires some qualification. The mode of failure is different for the two polymers. In the case of the PAA mud, no erosion takes place and approximately 5% water is embibed by the shale resulting in hole closure by swelling. PAA invades the swollen shale and glues the potentially erodable shale surface particles together and to the shale substrate.

In the case of containing the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592,4% water uptake and 20% erosion takes place prior to failure by collapse.

A possible explanation for the differing performances of the two products lies in their structure. Both are long chain molecules but the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592 (which consists of sugar units) is much bulkier due to its branched structure. Both molecules appear to have the required configuration and charge distribution to bind clay platelets but, presumably, the size of the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592 molecule prevents it invading the shale surface layer.

This unique property opens up new possibilities in the formulation of muds designed to drill swelling shale formations. Tight holes are a common problem when drilling with PAA-containing mud due to the fact that PAA reduces erosion of swelling shale formations: PAA is primarily added to the mud fo cutting encapsulation. The possibility now exists of using the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592 which will allow controlled erosion of the swelling shales and prevent shale cutting disintegration.

TABLE 1 Composition and properties of the base mud used for the cutting encapsulation tests Fresh water 8 kg/m3 carboxymethyl plastic viscosity = 15 cP (PV)** cellulose 10 kfg/m3 stabilose LU yield point = 2 Pa (YP)*** 1 kg/m3 paraformaldehyde TABLE 2 Mud composition and properties and test conditions in the triaxial shale test Fresh water 30 kg/m3 bentonite Confining pressure 225 bar 2.15 kg/m3 polymer pump speed : 61/mien (effective concentration) 100 kg/m3 KCI plastic viscosity = 10 cP yield point = 2.5 Pa * polymer is either hydrolysed polyacrylamide (PAA) or the heteropolysaccharide obtained from Pseudomonas sp. NCIB 11592.

** Plastic viscosity is defined on page 735 of the book "Drilling and drilling fluids" by G.V. Chilingarian and P. Varabutr (Elsevier Scientific Publishing Co. 1981).

Yield point is defines on page 740 of the above book.

TABLE 3 Results of the cutting encapsulation tests Product added Description Concentration Recovery (%) PV** YP** to the base mud (gll) 2 hrs 16 hrs (cP) Pa ENS heteropolysaccharide obtained 5 98 90 24 28 from Pseudomonas sp. NCIP 11592 Separan AP-273 hydrolised polyacrylamide 5 82 85 55 26 Base mud - - 55 30 15 4 water - - 61 8 1 0 ** = after 16 hours hotrolling at 60 C.

TABLE 4 Results of the triaxial shale tests Test polymer time of failure type of failure * sample sample no. water content erosion 1 PAA 259 min B 9.3 % 0.0 % 2 ENS 7240 min none - 3 ENS 710 min A 8.0 % 20.2 % 4 ENS 440 min A 8.2 % 20.5 % * = B : hole closure by swelling.

= A: hole collapse due to erosion/softening.

Claims (5)

1. A process for drilling a well in an underground formation in which process a drilling fluid is circulated in said well, while drilling, characterized in that the drilling fluid contains a hetero polysaccharide which has been obtained by cultivation of Pseudomonas sp. NCIB 11592.

2. A process as claimed in claim 1, characterized in that the drilling fluid contains 0.1 to 10 kg heteropolysaccharide per 1000 kg of fluid.

3. A process as claimed in claim 1 or 2, characterized in that the drilling fluid contains in addition to the heteropolysaccharide, at least one fluid loss additive, at least one thinner, at least one clay, at least one weighting agent, and/or at least one salt.

4. A process as claimed in claim 3, characterized in that the drilling fluid contains bentonite, baryte, one or more polymers, one or more starches, one or more lignosulphonates, gypsum, dolomite and/or lye.

5. A process as claimed in claim 1, substantially as described hereinbefore with reference to the Example.