Abstract

There is a growing awareness in the drilling industry that many cases of borehole instability may be caused by the changes in shale pore pressure resulting from fluid invasion. A hydraulic pressure differential, arising when the mud-column pressure exceeds the pressure in the shale pore fluids, drives fluid from the wellbore into the surrounding shale and propagates an expanding pressure front. The resulting changes in the effective stresses around the wellbore may then be sufficient to promote rock failure.

A new generation of water-based drilling fluids are being designed to minimise such pressure-penetration effects in pores by reducing either the shale's permeability to aqueous fluids or the rate at which fluids can flow into shales. The new thermally activated mud emulsion (TAME) system, utilising a combination of a surfactant solution and emulsion phases to reduce fluid entry into shales, is one of the first field-tested drilling fluids designed specifically to reduce borehole instability arising from the penetration of pressure into shale pores.

The first prototype TAME system comprises a conventional aqueous KCI-polymer drilling fluid containing a solution of an alcohol alkoxylate additive, components of which can undergo a phase transformation at downhole temperatures to form a fine emulsion. Both the solution- and emulsion-phase elements of the alkoxylate appear to make some contribution towards reducing rates of fluid flow into shales, although their exact mode of action is still unclear.

The prototype TAME system has been successfully field tested during 1992/93 in 17.5", 12.25", 8.5" and 6" sections of five deviated development wells and one exploration well in the UK North Sea. The overall conclusion from this test campaign is that the TAME system is superior to conventional KCI-polymer and polyglycerol muds by virtue of its better borehole stabilising qualities, higher rates of penetration, significant waste reduction and lower mud time rates (the total time spent drilling on bottom, tripping, conditioning the hole or mud and circulating the mud).

Following these encouraging field tests, TAME formulations have evolved to become Shell Expro's preferred fluid system for drilling reactive shales in standard exploration, appraisal and development wells.

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SPE Members

Abstract

Field data have been collected and analyzed to 1) identify the characteristics of a drilling fluid that enhance rate of penetration, and 2) quantify the impact of particular fluid properties on rate of penetration. The information is being used to evaluate the economics of a fluid treatment program in order to deliver optimal drilling performance and minimum drilling cost, rather than minimum fluid cost. Additionally, it is demonstrated how bit hydraulics can be improved through rheological modification without adjusting flow rate or nozzle size.

Introduction

It has long been known that drilling fluid properties can dramatically impact drilling rate. This fact was established early in the drilling literature, and confirmed by numerous laboratory studies. Several early studies focused directly on mud properties, clearly demonstrating the effect of kinematic viscosity at bit conditions on drilling rate. In laboratory conditions, penetration rates can be affected by as much as a factor of three by altering fluid viscosity. It can be concluded from the early literature that drilling rate is not directly dependent on the type or amount of solids in the fluid, but on the impact of those solids on fluid properties, particularly on the viscosity of the fluid as it flows through bit nozzles. This conclusion indicates that drilling rates should be directly correlative to fluid properties which reflect the viscosity of the fluid at bit shear rate conditions, such as the plastic viscosity. Secondary fluid properties reflecting solids content in the fluid should also provide a means of correlating to rate of penetration, as the solids will impact the viscosity of the fluid.

As the technical literature began to focus on the effect of different types and concentrations of solids, the industry began to turn its attention to the removal of those solids, but with little regard for the resulting viscosity of the fluid. Industry also began to recognize the wellbore stability benefits gained from low fluid loss muds, but once again ignored the effect that polymers and bridging solids added to the fluid to gain filtration control had on rheology, particularly high shear rate rheology. Low shear-rate rheology is often modified to provide for cuttings transport, which often raises the high shear-rate rheology as well, with potential detrimental effects on rate of penetration.

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The use of a high quality mud is an essential requirement to guarantee a successful drilling operation. The drilling industry aims to build wells at low costs and as fast as possible. Among other drilling problems, an adequately formulated drilling fluid will prevent wellbore instability while contributing to generate an in gauge borehole. Usually, one of the desired properties of a drilling mud is the least as possible interaction with the drilled formation. On the other hand, the idea of a chemically active fluid that would react with the rock to help improving drilling performance is very welcome. This kind of fluid should not only mitigate drilling problems but also contribute for the improvement of the overall process. The work presents the advances in drilling fluid technology to overcome the challenges that have arisen with the discovery of Pre Salt offshore Brazil, specially the drilling of long salt section containing highly soluble salt layers and the low penetration rates in hard carbonate rocks. An extensive theoretical and experimental work was carried out to assist drilling fluid design in this drilling scenario. A special fluid formulation developed to interact with carbonate rocks and increase penetration rate is presented. Although some important issues have yet to be addressed, the preliminary results show a good potential for the new technology.

Summary

The effects of bit hydraulics while drilling shale with a standard three-cone bit are examined in this paper. Tests were conducted by drilling into large-diameter, intact shale samples at simulated downhole conditions in Drilling Research Laboratory's wellbore simulator. The shale samples were recovered from massive surface outcroppings and preserved for laboratory use. The effects of hydraulic horsepower from 20 to 400 hhp and bit weights from 20,000 to 50,000 lbm on rate of penetration are presented.

Introduction

Most deep shales and some intermediate shales found in the U.S. are typically "slow" drilling formations. Efforts to improve rate of penetration in shale have been performed in both field tests and small-scale laboratory investigations. Until recently, laboratory drilling studies on shale have been confined to microbit¹ or single-cutter² studies because the ability to obtain and preserve large, intact shale samples had not been developed. In addition, laboratory facilities where full-scale drilling tests could be conducted at simulated deep-well conditions did not exist.

Massive surface shale formations have been located and techniques have been developed to extract and preserve large-diameter, intact samples. With these samples and the ability to simulate full-scale drilling conditions, a systematic, technical approach was taken where the effects of drill bit hydraulics were examined while drilling shale at simulated downhole conditions.

Background and Definitions

The in-situ conditions of a typical deep wellbore and surrounding rock formation are illustrated in Fig. 1. The formation is subjected to overburden stress, confining stress, wellbore pressure, and formation pressure. As previously demonstrated,^3-5 rate of penetration is influenced strongly by the bottomhole conditions and appears to be most sensitive to the differential pressure between the wellbore and formation. These effects, however, can vary widely depending on rock properties such as rock type, strength, density, permeability, and mud properties such as composition, filtration rate, viscosity, solids content, and particle size.⁶ Bit hydraulics - i.e., the means of removing cuttings from the hole bottom and cleaning the bit with the drilling fluid - are a key factor in improved bit performance. Bottomhole cleaning theories,⁷ microbit studies,⁸ and full-scale laboratory drilling experiments in hard, impermeable rock⁹ have shown the need for adequate bit hydraulics to maximize rate of penetration and avoid bit balling. Field tests with extended nozzles¹⁰ also have demonstrated great potential for increasing rate of penetration in certain formations with improved bit hydraulics. Some nondrilling laboratory studies have shown the effects of nozzle size on pressure distribution at the hole bottom.¹¹