This paper describes the design and qualification process used to select a reservoir drill-in fluid (RDF) for the Peregrino field offshore Brazil, and the successful application of this fluid. The Peregrino field is located east of Rio de Janeiro in the southwest Campos Basin area. Approximately 2.3 billion barrels of oil are in place in the Peregrino reservoir. The productive sands in this variable reservoir typically exhibit permeabilities between 6 and 15 Darcy, and are unconsolidated with interbedded shales. Peregrino crude oil is heavy (13API) and viscous. The estimated recoverable volume of crude oil is 300 million to 600 million barrels. The selected fluid, a NaCl brine-weighted water-based mud employing KCl and Glycol additions for shale stabilization, was used to drill the first wells at Peregrino. Penetration rates were high and zero non-productive time occurred. To achieve this drilling performance in the high permeability, unconsolidated, heavy oil reservoir, an extensive fluid selection process was performed to optimize the drill in fluid for maximum well productivity. Key test results reviewed in this paper include: Bridging solids optimization, lubrication, shale inhibition, fluids compatibility, filtercake lift off and backflow performance, breaker fluids and formation damage The reservoir sections of the wells were successfully drilled, open-hole-completed with sand screens and gravel packed with 100% efficiency.

When planning drilling operations for an oil or gas well, drilling fluid is a key factor to consider for a successful operation. Fluid selection depends primarily on two aspects. First, it must meet all specific technical requirements for the well. Second, it must comply with environmental regulations. Therefore, this selection should be evaluated in detail through specialized laboratory testing and engineering analysis. Factors, such as chemical selection, engineering, processes, and field execution contribute to both the conformance and performance of a drilling fluid. Technical requirements for a drilling fluid are distinct for each operation. However, in general terms, a drilling fluid should ensure wellbore stability, optimize drilling rates, provide effective hole-cleaning rheological properties, minimize pressure spikes while circulating, and transmit hydraulic power to downhole tools. Environmental requirements are region-specific and vary in terms of complexity, from relatively simple guidelines to manage parameters, such as ionic concentration limits, to specific chemical qualifications, such as bioaccumulation, biodegradation rates, and toxicity thresholds. To satisfy both technical and environmental requirements, fluid designs should be fine-tuned and customized in each region. A principal drilling operation objective is to minimize safety and environmental risks. As a result, operators and service companies take proactive initiatives to help minimize the likelihood of these risks during drilling operations. Personnel involved in drilling operations should know and comply with the directions in the drilling permit to help avoid environmental and safety incidents. Additionally, all personnel are encouraged to report potentially hazardous activities or circumstances through a variety of observational safety programs. The purpose of this technical paper is to provide knowledge for the oil and gas industry to help understand the governmental permissions in the Latin American region and considerations for selecting ecologically compatible drilling fluids and products in the region.

The mechanical friction generated during drilling operations can be problematic in long, narrow, deviated and highly inclined wells. Efforts to reduce the excessive friction include application of synthetic-based muds or oil lubricants. However, these fluids are highly restricted because of environmental concerns. Even adding small amounts of oil-based lubricants to water-based fluid can raise environmental and formation damage concerns.Shaker blinding issues were observed while drilling a heavy oil reservoir in the Peregrino field offshore Brazil. Based on field observations, the blinding was thought to be caused by a combination of the heavy crude oil, drill cuttings, and mud lubricant. An extensive laboratory study included simulation of screen blinding, a compatibility study between mud lubricants, heavy crude oil and drill cuttings, and, ultimately, a proposed solution based on a combination of mud additives to help to mitigate the problem.During this study, several lubricants and combinations of additives were subjected to a sensitivity study based on technical and environmental requirements to select an optimized and customized solution. The study included friction coefficient determination to compare the performance of proposed combinations and actual drill-in fluid being used. For the screen blinding simulation, a mechanical shift sieving apparatus was used. An unconventional lab test was adapted from existing completion fluids literature for the compatibility study.The study also included shaker screen visual and microscopy analysis, as well as analytical chemistry laboratory determination of the nature of screen blinding with elemental analyses, and Fourier transform infrared spectroscopy (FTIR). Grease, sieve, and emulsion potential tests were run using liquid additives from mud formulations described in previous lab testing for the screen blinding issue. For the emulsion potential tests, formulations were treated with 1% v/v crude oil and combinations of 1% v/v lubricants and solvents in an attempt to prevent/mitigate possible interactions of these components with the crude oil.A lubricant cocktail provided the best performance in the lubricity test, improving the lubricity coefficient from 0.303 (blank) to 0.15, with a torque reduction of 55.8%. The solution contained no grease and was formulated using environmentally acceptable components with minimal formation damage risk.

Circulation losses are frequently encountered during drilling operations. Therefore, the availability of various sizes and types of lost circulation materials (LCMs) to mitigate these losses are crucial to minimize nonproductive time (NPT) and costs related to the severity of fluid lost to the formation. This paper presents extensive laboratory testing performed to validate the effectiveness of novel LCMs intended for severe-to-total drilling fluid-loss control in overburden and reservoir formations. Two different families of LCMs were tested in a particle plugging apparatus (PPA) using metallic disks with various slot sizes that simulated different fracture widths under defined pressure and temperature conditions. Initially, low pressures were applied to validate the materials ability to form a plug over the slots. Next, high pressures were applied to validate the deposited plugs ability to maintain their shape, which indicates the fractures plugging effectiveness. Both LCM families easily released the continuous phase at differential pressures of 100 psi and deposited a uniform and firm wall cake that can rapidly seal a wide range of apertures (4 to 7 mm). The LCM plugs deposited on the simulated fractures provided effective pressure containment, withstanding differential pressures as high as 2,000 psi. Additionally, the evaluated materials were visually inspected, and their ability to release water and form a dry wall cake over any high-permeability slot was validated. Circulation losses are generally countered by mixing various types of LCMs to achieve a defined particle size distribution (PSD), which might only seal one size of fracture. This paper presents laboratory test results, which indicated the two LCM families could seal a wide range of fractures effectively. The first application of the studied LCMs in a naturally fractured ultradeepwater well is also presented.

In the Peregrino field, located in the Campos Basin offshore Brazil, the operator adopted the use of water-based drilling fluids for drilling development wells due to rig limitations. In the 12 ¼-in. sections of several wells drilled in this field, high dispersion of shale minerals suffered by the drilling fluid caused increments of viscosity, which subsequently affected the drilling process through higher-than-expected circulation pressures, dilution rates, and costs. Although the wells have been drilled within the estimated times and budgets, an improvement in the fluid inhibition capability was initiated. A detailed laboratory effort was conducted to obtain a combination of inhibitors capable of controlling excessive clay dispersion, minimizing fluid rock interaction, and reducing dilution requirements while helping to ensure an adequate rheological profile throughout the interval. Laboratory validation of the interaction between the fluid and rock samples provided a better understanding of the inhibition mechanisms and helped ensure that stability of the reactive minerals drilled could be maintained. Various additives were tested against samples of commercial-reactive and field-reactive clays. Product concentrations were adjusted to reduce the interaction between the drilling fluid and the formation while helping to ensure that fluid capabilities, such as cuttings suspension, filtration control, and bridging, were maintained. An adequate environmental profile to enable safe disposal of fluid in compliance with local environmental regulations was also obtained. After identifying an adequate solution, a detailed utilization plan was developed and put in place. To aid proper deployment while drilling, specific mixing procedures at the support liquid mud plant, transportation vessels, and at the rig site were determined. The next step was to assign a candidate well for the application – an Extended Reach Well (ERW) with step-out ratio of 2.9. While drilling the 12-¼-in. section of the pilot well with the proposed fluid technology, a significant improvement was observed on cuttings integrity, which led to a reduction in the required volume of dilution and a subsequent drilling fluids cost reduction Also, better hole quality and reduced operational risks were obtained. The well was safely drilled with a 76° sail inclination, 7938 meters of Measured Depth (MD) and 2368 meters of True Vertical Depth (TVD), and lessons learned from the first utilization of the described fluid system were implemented on subsequent wells to continue obtaining the benefits of the new fluid formulation. High Performance Water Based Drilling Fluids (HPWBDF) are not new and are thought by most to be a mature technology. However, advancements in water-based drilling fluid additives have enabled these systems to mimic the performance of non-aqueous systems more closely. This paper discusses how understanding the chemistry of the formations to be drilled and customizing chemical additive blends for those formations can help to improve operational efficiency and minimize costs.