Summary The occurrence of barite sag has been a well recognized but poorly understood phenomenon in the drilling industry resulting in problems such as lost circulation, well control and stuck pipe. The financial impact on drilling costs, usually resulting from rig-time lost while circulating and conditioning the drilling fluid system, is not trivial. Recurring barite sag problems reportedly have resulted in the loss of drilling projects. Originally thought to occur under static conditions, barite sag is recognized now to occur more readily under dynamic, low-shear-rate conditions. Industry experts have offered a variety of measuring parameters, based upon empirical data, that only partially correlate with the occurrence of barite sag. Prediction of barite sag in dynamic flow has created an engineering challenge. The effect of shear rate on dynamic barite sag, for invert-emulsion drilling fluids, has been studied and quantified using new and advanced technology. A new field viscometer capable of measuring viscosity at shear rates of 0.0017 sec–1 and an eccentric wellbore-hydraulics model were used to develop and understand this relationship. Changes in mud weight as a function of shear rate, hole angle, annular velocity (AV), and eccentricity correlate with ultralow-shear-rate viscosity. Based upon experimental results, field technology has been developed to predict the potential for barite sag of invert-emulsion drilling fluids and to provide remedial measures through ultralow-shear-rate-viscosity modification. The efficacy of using traditional rheological measurements as indicators of barite sag potential is addressed. Introduction Recent advances in drilling technology have resulted in greater numbers of directional wells being drilled as operators strive to offset ever-increasing operating costs. Deviated drilling allows operators to exploit reservoir potential by drilling multiple wells from a single site, and to increase production by penetrating the pay zone in a horizontal, rather than a vertical plane. With consideration to eliminating drilling problems such as torque and drag, stuck pipe, low rates-of-penetration and wellbore stability, these wells are being drilled increasingly with invert-emulsion drilling fluids. Despite their considerable technical merits and advantages, invert-emulsion drilling fluids are not always trouble-free. First, these fluids are generally more viscous at surface conditions than water-based drilling fluids, and efforts are made to reduce viscosity by minimizing additives used for suspending barite. Second, fluid flow in a deviated wellbore is skewed by the effects of drillpipe eccentricity, typically resulting in low shear rates under the eccentric pipe, creating conditions conducive to barite sag. As a result, the frequency of problems associated with barite sag when drilling highly deviated wells is higher with invert emulsions, compared with water-based systems. Prior Laboratory Studies In the field, barite sag is defined roughly as the change in mud weight observed when circulating bottoms-up. Several laboratory investigations of barite-sag mechanisms and potential have been undertaken over the past decade. Results from a laboratory study presented by Hanson et al.1 found that barite sag is most problematic under dynamic, not static, conditions. Results indicate that barite sedimentation and bed formation occur while drilling fluid is being circulated and that fluid-like beds can "slump" downward when circulation is stopped. An important conclusion from this work was that barite sag generally observed in the field is due primarily to barite deposition occurring under dynamic conditions. Bern et al.2 induced barite sag by circulating at low flow rates with an eccentric drillpipe. Drillpipe rotation tended to prevent bed formation and served to aid in removing beds formed on the lower side of the test section. The barite sag tendency of some fluids tested at low flow rates was so great that beds were observed "avalanching," slumping down the test section and being incorporated back within the system. The authors concluded that the combined effects of hole angle, low AV, and a stationary, eccentric drillpipe were conducive to inducing dynamic barite sag. There appear to be several "schools-of-thought" on the relationship between rheological properties and barite sag. Using laboratory devices to measure static barite sag, several researchers concluded that the API gel strength measurement is an unreliable indicator of static barite sag potential.3,4 Dynamic oscillatory techniques were used by Saasen et al.4 to measure the linear viscoelastic properties of near-static gel networks, and found to be reasonable predictors of static barite sag potential. Kenny and Hemphill5 showed that the Herschel-Bulkley yield-stress coefficient, t0, correlates with static barite-sag potential; however, they cautioned that t0 should not be the only parameter used for dynamic barite-sag predictions. The low-shear-rate-yield point (LSRYP), an extrapolated yield stress calculated from 6 and 3 rev/min readings, was deemed by Bern et al.6 to be a reasonable approximation of the true yield stress of a drilling fluid. They suggest that while the expertise exists to control static barite sag, the influence of rheological properties on dynamic barite sag is not well understood. A common theme in the published literature is that low-shear-rate viscosity is a rheological parameter of importance in determining the capacity of a drilling fluid to minimize or prevent the occurrence of barite sag, particularly dynamic barite sag.1–8 Most authors refer to "low-shear rate" as that corresponding to the 3 rev/min dial reading (~5.1 sec–1), the lowest operating speed of the 6-speed viscometer. Dye et al.9 recently concluded that the magnitude of dynamic barite sag in an eccentric annulus, using invert-emulsion drilling fluid, is highest at annular shear rates below 3 to 5 sec–1. This study demonstrated that viscosity measurements taken at ultralow shear rates (<2 sec–1) correlate with the management of dynamic barite sag. Theoretical Foundation of Study Drawing on the work of previous researchers, we postulated that dynamic barite sag can occur when:the drillpipe (or inner cylinder) is in a fixed, eccentric position, thereby ensuring a wide distribution of point velocities in an eccentric annulus;drilling fluids are circulated at constant shear-rate over an extended period of time; andviscosity levels at these shear rates are insufficient to retard barite sedimentation.
Summary A new water-based mud system was successfully introduced as a high-performance, environmentally compliant alternative to oil and synthetic emulsion-based muds (OBM/SBM). Historically, emulsion muds have been the systems of choice when drilling challenging onshore, continental shelf, and deepwater wells to minimize risk, maximize drilling performance, and reduce costs. However, environmental constraints, a high frequency of lost circulation, and the high unit cost of emulsion systems sometimes negate the benefits of their use. Conventional water-based muds (WBM) offer the benefits of environmental compliance, attractive logistics, and a relatively low unit cost but consistently fail to approach the drilling performance of OBM and SBM. The new high-performance, water-based mud (HPWBM) is designed to close the significant drilling performance gap between conventional WBM and emulsion-based mud systems. The system has undergone extensive field testing on very challenging onshore, deepwater, and continental shelf wells that would otherwise have been drilled with oil or synthetic-based muds. This paper provides a detailed, technical overview of the new system, discusses its inherent environmental advantages, and presents case histories comparing performance to offset wells drilled with emulsion and conventional WBM systems. Introduction The industry is increasingly drilling more technically challenging and difficult wells. Exploration and development operations have expanded globally as the economics of exploring and producing for oil and gas have improved with advancements in drilling technology. Advanced drilling operations such as deep shelf, extended reach, horizontal, and deepwater are technically challenging, inherently risky, and expensive. OBM and SBM have many inherent advantages over water-based drilling fluids, including temperature stability, tolerance to contamination, and corrosion protection. However, the fluid attributes of concern in this discussion are those most directly related to drilling performance and environmental issues. With consideration to reducing drilling problems such as torque and drag, stuck pipe, low rates-of-penetration, and wellbore stability, these wells are generally drilled with emulsion-based muds. Environmental legislation governing drilling waste is continually restricting the discharge limits of spent muds and drilled cuttings. Operators are challenged with achieving a balance between minimizing the potential environmental impact of the drilling fluid against drilling objectives. The inherent advantages provided by emulsion muds are increasingly being offset by environmental compliance restrictions.
fax 01-972-952-9435. AbstractDrilling in deep water environments, such as the Gulf of Mexico (GoM), presents the potential for a variety of wellbore and operational problems.Wellbore stability, rates-ofpenetration (ROP), hole cleaning, and pressure management are but a few of the key operational parameters affected by the choice of drilling fluid for a given well. Synthetic-base muds (SBM) provide excellent wellbore stability and maximum ROP, particularly in combination with PDC bits. Conversely, management of equivalent circulating density (ECD), pump initiation and surge pressures are more difficult to control with SBM due to the effects of temperature and pressure on rheological properties. The inability to effectively control these drilling parameters can result in catastrophic lost circulation events, which negatively impact operating costs arising from non-productive time (NPT), as well as the high unit cost of the SBM. This paper highlights the development and application of a new constant-rheology synthetic-based mud (CR-SBM), designed to overcome the problems associated with pressure management when using SBM in deepwater operations. Unlike conventional SBM, this new fluid exhibits a "constant rheology" profile under the conditions encountered in deepwater operations. With the fluid's constant rheology profile, downhole surge pressures and ECD are minimized, thus reducing the frequency and severity of lost circulation events. In addition, the CR-SBM has consistently facilitated delivery of hole cleaning and barite suspension objectives in directional wells.The CR-SBM presented in this paper is unique in the sense that the near constant profile of key rheological properties was achieved using organophilic clay and without the use of special emulsifiers. In general, the components of the CR-SBM are the same as conventional SBM. Case histories are presented that demonstrate the degree to which the new CR-SBM increases deepwater operational efficiency by reducing downhole mud losses and non-productive time.
The degree of difficulty and costs of oil and gas wells have continually increased over the past decade. Development operations continue as the economics of exploring and producing for oil and gas have improved with advancements in drilling technology. Advanced drilling technologies such as rotary stearable assemblies, logging-while-drilling (LWD) tools, annular pressure subs and new bit designs have improved the economics of performance-driven wells. With consideration of reducing drilling problems such as torque and drag, stuck pipe, low rates-of-penetration, depleted sands and well bore stability; these wells are generally drilled with non-aqueous fluids (NAF). However, the inherent advantages provided by NAF are increasingly being offset by environmental risks and liabilities. The paper discusses key criteria to be considered when selecting high performance fluids (HPF) for performance-driven wells.Performance-driven wells are classified as wells that are technically challenging and inherently risky and costly.These types of wells demand the use of HPF to contain costs and deliver well objectives. Additionally, a new high-performance water-based mud (HPWBM) has been developed and field tested as a technically competent and environmentally compliant alternative to NAF on performance-driven wells.Through a process of product substitution, ChevronTexaco has achieved project objectives while improving the environmental impact of using HPF. Introduction The industry is increasingly drilling more technically challenging and difficult wells.Exploration and development operations have expanded globally as the economics of exploring and producing for oil and gas have improved with advancements in drilling technology. Advanced drilling operations such as deep shelf, extended reach, horizontal and deepwater are technically challenging, inherently risky and expensive. Environmental legislation governing drilling waste is continually restricting the discharge limits of spent muds and drilled cuttings.Operators are challenged with achieving a balance between minimizing the potential environmental impact of the drilling fluid against drilling objectives.The inherent advantages provided by NAF are increasingly being offset by environmental compliance restrictions. The drilling process generates large volumes of drilled cuttings and waste muds.Beginning in the late 1970's it became evident that waste discharges from drilling operations could have undesirable effects on the marine ecology.1The United States Environmental Protection Agency (EPA) adopted national discharge standards for the oil and gas industries in 1993 that established restriction on oily sheens and aquatic toxicity testing for waste discharges.The American Petroleum Institute estimates that about 150 million barrels of drilling waste were generated in 1995 from onshore wells in the United States alone. Operators have used a variety of methods for managing drilling wastes, typically driven by governmental regulations and cost considerations.Three options exist to manage offshore wastes from drilled cuttings and spent drilling fluid: marine discharge, down hole injection, and onshore disposal.2All options have advantages and disadvantages with regard to total life cycle environmental impact, safety, cost, and operational performance. The environmental impact of discharging cuttings and spent water-based mud (WBM) is minimal; however, the waste from certain types of NAF can create impaired zones in the proximity of drilling operations.Currently, most synthetic-based mud (SBM) drilled cuttings can be discharged into marine waters, however, SBM whole mud discharge is not allowed.WBM whole mud and cuttings can be discharged provided the fluid meets aquatic toxicity standards.From an environmental perspective, the worst case is oil-based mud (OBM).Wells using OBM are categorized as "zero discharge" and there can be no discharge of cuttings or whole mud.All OBM-contaminated waste must be transported onshore for disposal or be injected underground at the well site.
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