Water-Free, Drill-In Fluid Dramatically Improved the Producibility of Sensitive Sandstone Reservoirs
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNew water-free, oil-based drill-in and completion fluids were recently utilized to drill a sensitive sandstone reservoir. Lower fluid densities were required to safely stabilize the wellbore compared to water-based fluids previously used in the offset wells. Avoiding excessive overbalance pressures eliminated differential sticking, minimized hole enlargement, and significantly reduced formation damage. Upon reaching the target horizontal depth, clean treated … Show more
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Cited by 7 publications
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As we approach an age of deeper discovery and petroleum producing wells with hostile environments, the industry need for an elevated-temperature, high-density, low-solids, and non-damaging reservoir drilling fluid or "drill-in fluid" has moved to the forefront of laboratory and applied research. Drill-in fluids are a special class of drilling fluids that prevent formation damage, provide superior hole cleaning, and help minimize wellbore cleanup effort, resulting in increased efficiency from the production reservoir. These fluids address the wide range of difficulties encountered in horizontal drilling, completion, and workover operations. The need for fluids with service temperatures above 300°F has increased beyond the capabilities of traditional biopolymers to create rheologically stable fluids. While some water-based drilling fluids excel at these higher temperatures, their formulations include non-acid soluble solids that are damaging to hydrocarbon-bearing formations and hence undesirable. With higher temperature reservoirs being drilled, there is need for a suitable high-density, high temperature stable drill-in fluid. For the development of the fluid presented in this work, various high density brines were evaluated to achieve fluid weights up to 17.6 ppg (2.1 sg) in order to reduce the amount of weighting agent utilized in the system since these solids can result in high plastic viscosities and create difficulty in the cake removal and clean-up processes. The total amount of CaCO3 bridging material was maintained at a relatively low concentration to produce a thin, acid-soluble filter cake while the bridging particle size was determined by the ideal packing order of the chosen pore size. The improved drill-in fluid was shown to possess thixotropic fluid rheology. Its additives are based solely on synthetic polymeric material for increased chemical and thermal stability. Hot-roll temperatures in excess of 355°F (180°C) were achieved with no loss in rheological properties. Introduction Advancements in drilling and completion technologies for improved returns on drilling investments have led to the development of radically new categories of drilling and completion fluids. Advanced drilling technologies, like high-angle, multilateral, slim-hole, and high-temperature, high-pressure (HTHP) extreme environment wells require fluids that provide maximum performance by maintaining effective suspension properties and a non-damaging behavior over a broad spectrum of conditions.1–3 Therefore a need exists for an improved drilling fluid system that meets both drilling and completion requirements and can be successfully applied for drilling operations in complex formations and under extreme thermal and pressure conditions. Over the last decade, major service companies have devoted extended research towards the development of a specialized category of drilling fluids for utilization within reservoir sections.4–13 The employment of such fluids has become an accepted best practice within the petroleum industry. Commonly referred to as reservoir drilling fluids (RDF) or drill-in fluids, these particular formulations are specifically designed to help prevent formation damage, minimize rig time, and provide maximum production efficiency. Although aqueous- and hydrocarbon-based fluid systems exist, brine-based drill-in fluids encompass the vast majority of RDFs used in field operations to date.14
As we approach an age of deeper discovery and petroleum producing wells with hostile environments, the industry need for an elevated-temperature, high-density, low-solids, and non-damaging reservoir drilling fluid or "drill-in fluid" has moved to the forefront of laboratory and applied research. Drill-in fluids are a special class of drilling fluids that prevent formation damage, provide superior hole cleaning, and help minimize wellbore cleanup effort, resulting in increased efficiency from the production reservoir. These fluids address the wide range of difficulties encountered in horizontal drilling, completion, and workover operations. The need for fluids with service temperatures above 300°F has increased beyond the capabilities of traditional biopolymers to create rheologically stable fluids. While some water-based drilling fluids excel at these higher temperatures, their formulations include non-acid soluble solids that are damaging to hydrocarbon-bearing formations and hence undesirable. With higher temperature reservoirs being drilled, there is need for a suitable high-density, high temperature stable drill-in fluid. For the development of the fluid presented in this work, various high density brines were evaluated to achieve fluid weights up to 17.6 ppg (2.1 sg) in order to reduce the amount of weighting agent utilized in the system since these solids can result in high plastic viscosities and create difficulty in the cake removal and clean-up processes. The total amount of CaCO3 bridging material was maintained at a relatively low concentration to produce a thin, acid-soluble filter cake while the bridging particle size was determined by the ideal packing order of the chosen pore size. The improved drill-in fluid was shown to possess thixotropic fluid rheology. Its additives are based solely on synthetic polymeric material for increased chemical and thermal stability. Hot-roll temperatures in excess of 355°F (180°C) were achieved with no loss in rheological properties. Introduction Advancements in drilling and completion technologies for improved returns on drilling investments have led to the development of radically new categories of drilling and completion fluids. Advanced drilling technologies, like high-angle, multilateral, slim-hole, and high-temperature, high-pressure (HTHP) extreme environment wells require fluids that provide maximum performance by maintaining effective suspension properties and a non-damaging behavior over a broad spectrum of conditions.1–3 Therefore a need exists for an improved drilling fluid system that meets both drilling and completion requirements and can be successfully applied for drilling operations in complex formations and under extreme thermal and pressure conditions. Over the last decade, major service companies have devoted extended research towards the development of a specialized category of drilling fluids for utilization within reservoir sections.4–13 The employment of such fluids has become an accepted best practice within the petroleum industry. Commonly referred to as reservoir drilling fluids (RDF) or drill-in fluids, these particular formulations are specifically designed to help prevent formation damage, minimize rig time, and provide maximum production efficiency. Although aqueous- and hydrocarbon-based fluid systems exist, brine-based drill-in fluids encompass the vast majority of RDFs used in field operations to date.14
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractInducing formation damage in sandstone reservoirs through poor drilling fluids management is a crucial factor that can affect well productivity. An integrated team assigned to manage drilling horizontal producers for field development, developed a mud management plan to monitor drilling fluid properties and maintain mud system specifications to minimize formation damage in the field's sensitive sandstone reservoir. This paper discusses the implementation of the engineered oil-based drillin fluid, particle size monitoring, and drilling and completion methods designed to minimize reservoir formation damage and help maximize well productivity.A particle size distribution (PSD) analyzer was used in the field to monitor the PSD values of the particulates in the drillin fluid (DIF) while drilling the sandstone reservoir. Core samples were selected and analyzed using a scanning electron microscope (SEM) to determine an average pore size value.A diesel-based DIF was specifically designed to minimize formation damage. The DIF was formulated with a 70/30 oil water ratio and was treated with a sized calcium carbonate bridging agent to help minimize spurt/total loss. The engineered bridging agent was added to prevent formation damage that results from the invasion of fines. Overbalance pressures were also minimized to avoid the risk of differential sticking.For better bridging results, the D90, D50 and D10 particle size distributions were instantaneously maintained in the programmed range while drilling the entire sandstone pay section with controlled rates of penetration (ROP). The % of drill solids as a function of total solids was also maintained at low levels with the use of centrifuges and addition of whole treated mud. Upon reaching the total depth (TD), the bottomole assembly (BHA) was changed to a reaming assembly and the entire open-hole section was reamed to TD.After making a wiper trip, the operator tripped back to bottom without pumping to simulate hole conditions that would occur while running screens. Once the open hole was deemed in good condition the well was displaced to a solids-free invert emulsion mud maintained at the same density as the DIF. This fluid was circulated over a 230-mesh screen prior to running the screens to ensure that all fine sand and excess filter cake were removed.To date, 26 wells have been successfully drilled and completed with sand screens using the abovementioned methodology. Testing results of the first three wells indicated minimum skin damage and good and stable production rates.
Brine-based reservoir drilling fluids are a special class of fluids designed to minimize formation damage, provide the necessary hole cleaning, help reduce wellbore cleanup time and cost, and allow reservoirs to be produced to the maximum of their potential. These fluids should address the wide range of difficulties frequently encountered in horizontal drilling, completion, and workover operations. Filtration control chemicals for currently available drill-in fluid systems exposed to extremely high bottomhole temperatures and pressure conditions are not effective or stable for drilling long horizontal sections of the reservoir. Failure to secure a low filtration rate and thin wallcake causes stuck pipe and loss of expensive downhole tools.Conventional fluid loss control additives for high performance brine-based drill-in fluids include nonionic water soluble polymers, such as starches, derivatized starches, gums, derivatized gums, and cellulosics. Cross-linked starches are often considered the benchmark of performance for utilization in reservoir fluids, but they do not have the thermal stability required for successful deployment at temperatures exceeding 300°F for extended contact periods.Conventional linear synthetic polymers are also utilized, but oftentimes they require another additive, such as phyllosilicate particles, to be able to effectively function as fluid loss control additives. The use of clay can be problematic in drill-in fluids, as removing the clay from the formation can be difficult because it infiltrates into pores. Furthermore, the addition of the linear synthetic polymers dramatically increases the viscosity of the fluid, which can result in increased equivalent circulating densities (ECD) and decreased drilling rates.Through advanced synthetic polymer techniques, a novel polymeric fluid loss control additive has been developed for brine-based reservoir drill-in and completion fluids. The new polymer provides enhanced thermal stability to temperature in excess of 400°F in monovalent and divalent halide brines. This paper presents detailed fluid formulations and discusses the polymer evaluation data under simulated downhole HPHT conditions.
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