Along with exorbitant costs and safety considerations, drilling an exploratory well where conventional mud systems could not maintain wellbore stability and trouble-free drilling, also posed the additionally difficult challenge of selecting a fluid system stable against multiple contaminants and flexible for a broad range of densities. The demands are compounded dramatically when designing the system and information to support the decision is poor. This paper details the design and performance of a silicate-based fluid, which is an inhibitive mud system formulated with a soluble silicate for maximum shale inhibition. The system has been developed to drill water-sensitive reactive shales and dispersible chalk and illite formations. The degree of inhibition provided by the silicate system is significantly greater than any other water-based system, truly approaching the level of an oil-based system. The authors will discuss the design and the application of the drilling fluid, which was selected to drill a formation containing anhydrite, claystone, dolomite and salt. The system was formulated to be salt-saturated to avoid dissolution of salt layers; to withstand anhydrite contamination; to be flexible for densities up to more than 2.0 kg/dm3 while maintaining its high level of inhibition. Though comprehensive lab tests were performed, the possible depletion of silicate while drilling the anhydrite-containing formation remained. Nevertheless, this challenge was accepted with tight wellsite engineering planned to maintain the fluid properties. Six wells have now been drilled with the proposed silicate system, with each showing very good performance and stable behavior in the above mentioned environment. The authors will present its effectiveness, formulation, properties, maintenance and lessons learned, along with the coordination and pre-planning that contributed to its successful application. Introduction Using sodium silicate in water-based muds was first undertaken in the 1930s.1,2 These systems, known as protective silicate muds, were successful at drilling very reactive shales but the control of their rheology proved difficult and they were superseded by the introduction of natural organic dispersants to treat bentonite muds. Further field trials were undertaken in 1960s by Darley which again failed to establish silicate-based muds as accepted systems.3,4 In the 1980s, Wingrave's research on shale stability found that silicates, used in conjunction with the potassium ion and specific polymers, combined for an effective shale-stabilizing package.5 During the last decade the industry has effectively used sodium silicate in conventional polymer fluid formulations to provide an effective water-based shale stabilizing system.6–9 Since the reintroduction of silicate fluids, more than 450 wells have been drilled around the world.10 From the North Sea to India to Australia, silicate-based drilling fluids have demonstrated superior performances: optimum inhibition characteristics, high penetration rates, reduced trouble time and superior wellbore integrity, optimum solids removal performance, minimal environmental impact.11 The outstanding inhibition of the silicate system comes from three directions: through chemical bonding of silica oligomers onto surfaces of drill cuttings and formation, through precipitation of the silicate with divalent ions, and through silicate polymerization that results in complex inorganic polymer structures, forming a protective layer on all surfaces (Fig. 1). Silicate-based fluids also generate firm inhibited cuttings, which contribute to optimum performance of the solids-control equipment and greatly enhanced formation evaluation. With the contamination of solids minimized, dilution rates, in turn, are reduced considerably, as are the costs associated with waste management. The unique cuttings integrity provided by silicate-based muds is reflected in Fig. 2, showing the cuttings of a KCl-based mud, before and after treating it with sodium silicate. Silicate chemistry Soluble silicates are the metal salts of silicic acid that exist in multiple polymeric forms in solution. Amorphous solids and powders are also manufactured.

The paper is based on laboratory research and field evaluation data incorporated in a study carried out to select a suitable drill-in fluid for use in naturally fractured HTHP sour gas reservoirs. Laboratory results were verified by monitoring drilling process and initial production of a particular well located at the gas condensate field in SW Pannonian Basin, Croatia. Production zone, naturally microfractured limestone (21% porosity, 2 md matrix permeability) at 2500–2600 m (BHST˜150°C) was left openhole. Reservoir fluid contains 53% CO2 and 800 ppm H2S. Two aspects of a drill-in fluid evaluation were considered: optimal drilling process performance, complicated by harsh reservoir conditions; and minimizing formation damage of plugging susceptible microfracture system. Drilling data, using the selected drill-in fluid, showed a good ROP and borehole stability. Production tests after well completion indicated no damage. Even under extreme down hole conditions, the balance between optimal drilling performance and minimal formation damage could be achieved using described laboratory testing procedure. Introduction The problem of formation damage of naturally fractured reservoirs due to drilling fluid invasion has been reported in petroleum engineering literature only sporadically.1–5 Mechanism of formation permeability reduction in this type of reservoirs 2–7 is in most cases associated with solid particles plugging the fissure-dominated flow paths of hydrocarbons to the wellbore. On the other hand, a drilling practice in such fractured rock systems is faced with many difficulties such as drilling fluid losses, well control uncertainty, cementing job complications etc. In cases where reservoir temperature is considerably high (>150°C) and formation fluid is aggressive (sour gas), a drilling process designed to keep up the optimal drilling performance 8–11 (i.e. high ROP, good borehole stability), as well as minimize formation damage 1–5,9,12,13 of the payzone, could be very hard to establish and maintain. In order to avoid the classical formation damage and drilling practice problems experienced with conventional drilling muds, the drill-in fluids 1,2,8,10,12,13 have recently been designed to drill through the productive zone. Standard procedure consists of drilling with conventional fluids to the top of the payzone 12, and then switching to the cleaner, less damaging drill-in fluid to drill through the hydrocarbon bearing zone. Although drill-in fluids are inherently less damaging than conventional drilling muds, some specific types of permeability reduction can occur in case of naturally fractured reservoirs 2. If a particle-laden fluid is introduced into micro-fracture system under HT conditions, solid particles are captured inside fractures, thus reducing the natural reservoir permeability in near-wellbore zone. A study for selection of the proper drill-in fluid for high-temperature, sour gas, naturally fractured 14 reservoir was performed in order to avoid the payzone damage and maintain the optimal drilling performance. Laboratory results of investigations were verified by monitoring the drilling process and initial production of a particular well located at the gas field in SW Pannonian basin, Croatia. Even under extreme down hole conditions at that well, the balance between optimal drilling performance and minimal formation damage was achieved using the proper laboratory testing procedure. The selected drill-in fluid fulfilled both (often controversial) aspects of drill-in fluid optimization in naturally fractured reservoirs. Reservoir Characteristics Principal reservoir properties of the subject gas field are summarized in Table 1. Reservoir rock is a pure, rather homogeneous limestone with some dolomitic intrusions. This was confirmed by XRD analysis and acid solubility tests. Solubility of rock samples in 15% HCl and in 10% CH3COOH was virtually 100%.

fax 01-972-952-9435. AbstractAlong with exorbitant costs and safety considerations, drilling in a high-temperature, high-pressure (HTHP) environment also poses the difficult challenge of protecting a reservoir that is all-too-often depleted. In areas where environmental restrictions and compatibility issues in gas fields prohibit the use of an oil-base drilling fluid, engineering a water-base fluid system that is free of potentially damaging solids, stable at very high temperatures, and able to withstand acid gases (CO 2 , H 2 S) or other contaminants is a very difficult proposition. The demands are compounded dramatically when drilling a deviated or a re-entry deviated slim hole well in an HTHP environment. Furthermore, since pressure and temperature heavily influences the rheological behavior, it is extremely difficult to calculate, predict and control pressure losses, ECD, and/or ESD in real time to avoid total losses or kicks.This paper details the design of a unique water-base reservoir drill-in fluid and its successful application on five HTHP wells in the Kalinovac and Molve gas fields of Croatia. Four of the wells were high-angle re-entry slim holes. Using laboratory, field, reservoir investigation and computer data, the authors will demonstrate the effectiveness of the new fluid in delivering zero skin damage and subsequently higher production rates than other wells in the field. Further, the system significantly reduced operating costs by eliminating costly stimulations, while simplifying the generation of clear imaging logs. The system also remained stable at bottom hole temperatures of 180 -200°C.During the drilling operations, a unique software program was employed that accurately predicted the rheological behavior, pressure losses, ECD and ESD, which contributed heavily to the wells being drilled trouble-free. The authors will detail the formulation of the new system, along with the coordination and pre-planning that contributed to its success in Croatia. The new water-base system has shown the effectiveness in drilling HTHP wells in areas where invertemulsion drilling fluid systems are prohibited.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe paper is based on laboratory research and field evaluation data incorporated in a study carried out to select a suitable drill-in fluid for use in naturally fractured HTHP sour gas reservoirs. Laboratory results were verified by monitoring drilling process and initial production of a particular well located at the gas condensate field in SW Pannonian Basin, Croatia.Production zone, naturally microfractured limestone (21% porosity, 2 md matrix permeability) at 2500-2600 m (BHST 150°C) was left openhole. Reservoir fluid contains 53% CO 2 and 800 ppm H 2 S.Two aspects of a drill-in fluid evaluation were considered: optimal drilling process performance, complicated by harsh reservoir conditions; and minimizing formation damage of plugging susceptible microfracture system.Drilling data, using the selected drill-in fluid, showed a good ROP and borehole stability. Production tests after well completion indicated no damage.Even under extreme downhole conditions, the balance between optimal drilling performance and minimal formation damage could be achieved using described laboratory testing procedure.

fax 01-972-952-9435. AbstractAlong with exorbitant costs and safety considerations, drilling in a high-temperature, high-pressure (HTHP) environment also poses the difficult challenge of protecting a reservoir that is all-too-often depleted. In areas where environmental restrictions and compatibility issues in gas fields prohibit the use of an oil-base drilling fluid, engineering a water-base fluid system that is free of potentially damaging solids, stable at very high temperatures, and able to withstand acid gases (CO 2 , H 2 S) or other contaminants is a very difficult proposition. The demands are compounded dramatically when drilling a deviated or a re-entry deviated slim hole well in an HTHP environment. Furthermore, since pressure and temperature heavily influences the rheological behavior, it is extremely difficult to calculate, predict and control pressure losses, ECD, and/or ESD in real time to avoid total losses or kicks.This paper details the design of a unique water-base reservoir drill-in fluid and its successful application on five HTHP wells in the Kalinovac and Molve gas fields of Croatia. Four of the wells were high-angle re-entry slim holes. Using laboratory, field, reservoir investigation and computer data, the authors will demonstrate the effectiveness of the new fluid in delivering zero skin damage and subsequently higher production rates than other wells in the field. Further, the system significantly reduced operating costs by eliminating costly stimulations, while simplifying the generation of clear imaging logs. The system also remained stable at bottom hole temperatures of 180 -200°C.During the drilling operations, a unique software program was employed that accurately predicted the rheological behavior, pressure losses, ECD and ESD, which contributed heavily to the wells being drilled trouble-free. The authors will detail the formulation of the new system, along with the coordination and pre-planning that contributed to its success in Croatia. The new water-base system has shown the effectiveness in drilling HTHP wells in areas where invertemulsion drilling fluid systems are prohibited.