Invert Emulsion Drilling Fluid Research Articles

PH-responsive water-in-oil emulsions with reversible phase inversion behavior stabilized by a novel dynamic covalent surfactant

The dynamic covalent nature of imine bonds provides a facile avenue to develop stimuli-responsive emulsifiers and has attracted considerable interest. In petroleum engineering, the development of smart emulsifiers that can be switched on demand to achieve the reversible phase inversion of the invert emulsion drilling fluid (IEDF) can effectively aid in its removal during cleanup. To this end, a novel dynamic covalent surfactant (TA-CBA) that can precisely manipulate the emulsion type by responding to acid/base stimuli was synthesized through the Schiff base reaction between 1-tetradecylamine (TA) and 4-carboxybenzaldehyde (CBA). Evaluation of the surface tension and interfacial tension (IFT) showed that the imine-bonded product TA-CBA was a surfactant with strong IFT reduction ability. At pH 7.4, the prepared water-in-oil (W/O) emulsions were stable without any separated phases after storage for 48 h and even after high-temperature aging at 210 °C. As the pH decreased from 7.4 to 4, the emulsion inverted from a higher viscosity W/O emulsion to a lower viscosity oil-in-water (O/W) emulsion. Remarkably, after the pH was adjusted back to 7.4, the rheological parameters and stability of the emulsion could be triggered at the original W/O emulsion level. 1H NMR and IFT measurements revealed that the reversible formation and breakage of covalent imine bonds led to the production of CBA and cationic amine salt (TA+), establishing the pH reversibility of the emulsion type and its rheological properties. Finally, we successfully formulated a reversible IEDF using TA-CBA as the sole emulsifier, which not only has reasonable rheological properties, filtration performance, and emulsification stability but also allows for easy cleanup. The IEDF can be phase-inverted into a water-soluble O/W emulsion drilling fluid at pH 4 and achieved a removal efficiency of 98.13 %.

Improvement of Emulsion Stability and Plugging Performance of Nanopores Using Modified Polystyrene Nanoparticles in Invert Emulsion Drilling Fluids.

Drilling fluid invasion and pressure transmission caused by the development of micropores and fractures in shale oil and gas formations are the major factors contributing to wellbore instability during drilling using oil-based drilling fluids (OBFs). In this study, a modified polystyrene latex (MPL) material was synthesized through emulsion polymerization and was characterized using Fourier transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), particle size analysis, scanning electron microscopy (SEM) observations, and contact angle testing. The influence of the MPL on the stability of a water-in-oil emulsion was analyzed via sedimentation observations and electrical stability tests. The effects of the MPL on the plugging mechanism of white oil and water-in-oil emulsions were evaluated using 0.1–1.0 μm micro-porous filtration films. The experimental results revealed that the MPL has a favorable thermal stability, with an initial thermal decomposition temperature of 363°C, a median particle size (D50) of 233 nm, and a three-phase contact angle of 103.5°. The MPL can enhance the sedimentation stability of an emulsion to a considerable extent and can improve the electrical stability (ES) of the emulsion, which is conducive to the stability of OBFs. Due to the deformability of the MPL, it has a wide range of adaptations for micro-scale pores and fractures. In both the white oil and water-in-oil emulsions, the MPL can reduce the filtration loss through microporous membranes with pore sizes of 0.1–1.0 μm to within 10 ml. This paper details the methodology of the synthesis of nanomaterials that can effectively plug a formation’s nanopores and fractures; thereby, stabilizing OBFs.

On the attributes of invert-emulsion drilling fluids modified with graphene oxide/inorganic complexes

Drilling fluid properties can be modified using a variety of nano-additives to achieve specific rheological and physical characteristics. Selected invert-emulsion drilling fluids modified with three different kinds of graphene oxide (GO)-based nanomaterials including GO, Cu(II) salen, and Cu(II) salen@GO were focused. The corresponding formation damage was evaluated through a set of core-flooding experiments and computed tomography analyses on selected carbonate samples followed by a set of wettability-based analyses and electrical conductivity measurements. The results were best fitted using the Casson model while the employed nano-additives were evidenced to have negligible effect on reducing the depth of penetration. In addition, GO- and Cu(II) salen@GO additives were observed to decline the contact angle for more than 20% and 35% in carbonate and sandstone samples, respectively, suggesting their potential to resolve the wettability alteration issues. Furthermore, electrical conductivity of the drilling fluid samples was increased for about 33 % using both Cu(II) salen and Cu(II) salen@GO additives.

Invert-emulsion drilling fluids for exposing Hamakin horizon of the Vostochno-Alinskoye oil and gas condensate field

The article is devoted to an analysis of the oil well construction in the fields of the Talakan group of Eastern Siberia. The low quality of the construction of oil wells is explained based on geological structure of the reservoir and the conditions of its formation, particulary, the complications encountered during drilling are given. Based on the analysis, it was found that the use of traditional monosalt and salt-saturated drilling muds is not effective enough to simultaneously solve the problems of exposing intervals of salt deposits and high-quality primary exposing of reservoirs. Based on the literature data analysis and the experience of building the first exploratory wells in Eastern Siberia, the use of hydrocarbon-based flushing liquids is justified. As a result of theoretical and laboratory studies, the compositions of invert-emulsion drilling fluids are proposed of hydrocarbons, which are available in the conditions of fields in Eastern Siberia. The results of studies for determining the effect of flushing fluids on the reservoir properties of the V10 reservoir of the Vostochno-Alinskoye oil and gas condensate field showed that recovery of core permeability after exposure to hydrocarbon-based flushing liquid was on average 90 %, which is significantly higher compared to the effect of water-based drilling muds, where the recovery coefficient is 23 %.

A Novel Solution for Severe Loss Prevention While Drilling Deep Wells

The loss of circulation is a big problem in drilling operations. This problem is costly, time-consuming and may lead to a well control situation. Much research has investigated the effectiveness of using different chemicals as lost circulation material (LCM) to stop mud and cement slurry losses. However, there remain many limitations for using such LCM types, especially when it comes to field applications. This paper presents a new high strength lost circulation material (HSLCM) that could effectively be used for managing severe lost circulation cases. The HSLCM could easily be pumped into the thief zone where it forms a gel that solidifies after a setting time to provide sealing between the wellbore and the thief zone. With this technique, the material stops the circulation losses, and hence enhances the well bore stability by reducing the well bore stresses. The HSLCM has a high compressive strength and it has a high acid solubility of around 96%. Because the HSLCM has high tolerance towards contamination, it can be utilized with water-based mud or invert emulsion-drilling fluids, hence providing a wide window of applications with the drilling fluids. In this study, laboratory experiments were conducted to evaluate the rheology, thickening time, compressive strength, and acid solubility of the HSLCM. The results showed good performance for the HSLCM as LCM. In addition, a case field study is presented which shows a successful field treatment for severe losses.

Mitigation of barite sagging during the drilling of high-pressure high-temperature wells using an invert emulsion drilling fluid

Sagging of particles is one of the most critical issues when drilling deep oil and gas wells especially when the hole angle is greater than 30°. Accumulation of cuttings at the bottom of the hole around the drilling bit as a result of barite sagging cause severe problems such as the loss of well control. Temperature has a major effect on barite sagging so there is a need to develop a new drilling fluid formulation that can prevent barite sagging under different geometries of hole path and high temperatures (greater than 300 °F).The objective of this study is to evaluate the effect of using an organophilic phyllosilicate (OP) as an anti-sagging additive to prevent barite sagging in an invert emulsion drilling fluid (IEDF) at high temperature (350 °F). Static sag tests were conducted at vertical and inclined (45°) positions at 350 °F. Dynamic sag tests were performed at 120 °F. The second objective is to determine the optimum concentration of OP and evaluate the effect of the selected concentration on the rheological and filtration properties of the IEDF at 350 °F.The results show that the optimum amount of OP for preventing barite sagging at 350 °F in both vertical and inclined positions is 1.5 g. Adding 1.5 g of the OP prevents barite sagging under dynamic conditions and enhances the rheological properties by increasing the yield point plastic viscosity ratio. The OP enhances the suspension capability of the drilling fluid at low shear rate (3 rpm).

Optimization of nano-silica in enhancing the properties of synthetic based drilling fluids for tight gas reservoir conditions

The nano-silica in drilling fluids is commonly used to improve the performance of drilling fluids, mainly water and oil based muds. Tight gas reservoirs are experienced a myriad of problems during drilling. One of the problems is the gas influx into the wellbore because of the abnormal pore pressure, fluid loss due to the fracture pressure and pore pressure is very narrow margin, stuck down hole equipment in the wellbore due to high differential pressure between hydrostatic pressure and pore pressure. Another problem is related to drilling mud and cement. However, not much studies have been done on the effect of nano-silica in invert-emulsion drilling fluids. This research paper focuses on how nano-silica influences the performance of invert-emulsion/synthetic based mud in tight gas reservoirs at harsh operation conditions, high pressure high temperature (HPHT). Synthetic based mud has been selected as an ideal drilling fluid to be used in HPHT tight gas reservoirs due to its superior qualities. In order to objectify this study, numerous experiments sets have been carried out in which different concentrations of nano-silica with respect to the fluid loss agent have been added to the synthetic based mud and the resultant performance is carefully studied in order to determine the optimum concentration of nano-silica that will elicit the best performance from synthetic based drilling fluids. The obtained results showed that a maximum concentration of about 40% provides the best performance Nano-silica has also improved the rheological properties of SBM by reducing the plastic viscosity and yield points.

Enhancing the Stability of Invert Emulsion Drilling Fluid for Drilling in High-Pressure High-Temperature Conditions

Drilling in high-pressure high-temperature (HPHT) conditions is a challenging task. The drilling fluid should be designed to provide high density and stable rheological properties. Barite is the most common weighting material used to adjust the required fluid density. Barite settling, or sag, is a common issue in drilling HPHT wells. Barite sagging may cause many problems such as density variations, well-control problems, stuck pipe, downhole drilling fluid losses, or induced wellbore instability. This study assesses the effect of using a new copolymer (based on styrene and acrylic monomers) on the rheological properties and the stability of an invert emulsion drilling fluid, which can be used to drill HPHT wells. The main goal is to prevent the barite sagging issue, which is common in drilling HPHT wells. A sag test was performed under static (vertical and 45° incline) and dynamic conditions in order to evaluate the copolymer’s ability to enhance the suspension properties of the drilling fluid. In addition, the effect of this copolymer on the filtration properties was performed. The obtained results showed that adding the new copolymer with 1 lb/bbl concentration has no effect on the density and electrical stability. The sag issue was eliminated by adding 1 lb/bbl of the copolymer to the invert emulsion drilling fluid at a temperature >300 °F under static and dynamic conditions. Adding the copolymer enhanced the storage modulus by 290% and the gel strength by 50%, which demonstrated the power of the new copolymer to prevent the settling of the barite particles at a higher temperature. The 1 lb/bbl copolymer’s concentration reduced the filter cake thickness by 40% at 400 °F, which indicates the prevention of barite settling at high temperature.

Study on the Preparation and Properties of Hybrid Lubricant for Invert Emulsion Drilling Fluids

A hybrid lubricant for invert emulsion drilling fluids (IEDFs), especially for high density (ρ>1.8 g/cm3) IEDFs, was synthesized with expanded graphitic oxide, 1,3-dichloro-2-propanol and N,N-dimethylhexadecylamine in our laboratory. The characterization of the hybrid lubricant was studied through scanning electron microscope (SEM), nuclear magnetic resonance hydrogen spectroscopy (1H NMR) and thermogravimetry analysis (TGA). The results demonstrated that the structure of the hybrid lubricant was consistent with design. This lubricant can adhere to the wellbore and the string directionally and then form a dense protective lubricant film, which causes a drastic reduction of coefficient of friction (CoF) between the rotating drill string and the casing or the rock formation. Application tests in IEDFs with various density showed that 50-70% CoF reduction was observed with 1.0-1.5 w/v% hybrid lubricant. In contrast, CoF reduction of conventional lubricants was only 30-40% at the same condition. And the hybrid lubricant even performs well under high temperature up to 180oC in the drilling fluids with a high density of 2.5 g/cm3 and has little influence on the rheology of drilling fluids. Additionally, the hybrid lubricant is proved easily degradable.

Determination of the Rheological Parameters of Invert Emulsion Drilling Fluid in Real Time using Non-Linear Regression Technique

Determination of the Rheological Parameters of Invert Emulsion Drilling Fluid in Real Time using Non-Linear Regression Technique

Case Study Shows Benefits of Applying Hollow Glass Spheres to Drilling Fluids

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174010, “Hollow-Glass-Sphere Application in Drilling Fluids: Case Study,” by Arminder Minhas, SPE, Halliburton; Brandon Friess, SPE, Farid Shirkavand, and Barry Hucik, Seven Generations Energy; Teresa Pena-Bastidas, 3M Canada; Bradley Ross, SPE, Halliburton; and Shawn Servinski and Frank Angyal, Seven Generations Energy, prepared for the 2015 SPE Western Regional Meeting, Garden Grove, California, USA, 27–30 April. The paper has not been peer reviewed. In an effort to optimize drilling operations and economics, an operator examined the effect of adding hollow glass spheres (HGSs) directly to the drilling fluid instead of performing underbalanced drilling. Both nitrogen and HGSs were believed to reduce hydrostatic pressure of the mud column in the hole, resulting in higher drilling rates of penetration (ROPs) and reduced mud losses to the wellbore. This paper provides information on HGSs as an economic alternative to nitrogen to help reduce the hydrostatic pressure of invert-emulsion drilling fluids. Introduction This case study focuses on the application of HGSs in two different sections of the drilling operation—a horizontal section and a vertical intermediate section. Data from a base-case horizontal section using an all-oil drilling fluid were compared with data of another well on the same drilling pad using the same fluid with the addition of HGSs. The intermediate-section data were from a base-case well that used an invert-emulsion drilling fluid, and they were compared with data from other intermediate well intervals in the same field that used an invert-emulsion drilling fluid with the addition of HGSs. Use of HGSs in Drilling Fluids HGSs are inert materials that are used as density-reducing agents. In the oil and gas industry, they are used for reducing the density of drilling fluids and cement blends. These hollow spheres (Fig. 1) are chemically inert, thermally stable (with a softening temperature of 600°C), and made of soda-lime borosilicate with a high strength/density ratio, and they can be added to both oil- and water-based fluids. A density reduction of up to 2.086 lbm/gal is possible when using HGSs. HGS addition helps reduce density and, consequently, the effective circulating density (ECD). Addition of HGSs to a lightweight drilling fluid allows consistent, stable properties and allows for measurement while drilling and controlled management of fluid properties. These lightweight fluids can be used for drilling at balanced, near-balanced, or underbalanced conditions. Applications include depleted reservoirs, geologically fractured formations, poorly consolidated formations, and high-permeability formations. In general, a reduction of differential pressure can result in the elimination of differential sticking, reduction or elimination of fluid loss, and mitigation of formation damage. This can result in higher productivity during drilling operations and during production.

Clay-Free Invert Fluid in High-Temperature Well Provides Consistent Low ECD Profile

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166538, ’Case History: Clay-Free Invert Fluid in Norwegian High-Temperature Well Provides Consistent Low ECD Profile,’ by Mads Rodsjo, SPE, and Erik Akutsu, Det Norske Oljeselskap, and Steven Morris, SPE, and Renate Mikalsen, Halliburton, prepared for the 2013 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 3-6 September. The paper has not been peer reviewed. Historically, invert-emulsion drilling fluids (IEFs) require organophilic clays to provide viscosity_and suspension characteristics. While effective, these_chemicals are prone to stratification in certain conditions, slow_chemical-reaction times, high pressure spikes, and high equivalent circulating densities (ECDs). This paper_describes the first application of clay-free IEFs in the Norwegian continental shelf (NCS), with an emphasis on an impressively low and consistent ECD contribution. Further, a treatment was developed to allow the IEFs to be used to drill into a section exhibiting temperatures greater than 160°C. Introduction IEFs have been used in the NCS for almost 50 years. These systems commonly use organophilic clays and lignites as their primary viscosifiying and filtration-control agents. IEFs containing these compounds have been found to exhibit a higher propensity for fluid stratification than IEFs that use polymers for viscosity and filtration control. Until recently, organophilic clays and lignites have been the primary means to provide viscosity and filtration control in IEFs. While these chemicals are effective, there are several inherent limitations, including high pressures spikes when applying force following a static period and stratification of the fluid. The latter can lead to settlement of weighting agents in a wellbore. In addition, organophilic-clay additives are known to react much slower than polymer-based additives, reducing their effectiveness to maintain fluid properties. This can lead to destabilization of the fluid such that stratification and high filtrate loss can occur, leading to instances of stuck pipe and poor hole cleaning and to wellcontrol concerns. Polymer-based viscosifiers generate suspension characteristics by seemingly unconventional and contradictory means; high gel strengths are generated extremely rapidly but are easily broken. Because of such behavior, they are often referred to as strong yet fragile gels. In addition, at low fluid densities, these systems are less likely to induce losses through decreased solids loading, which can often be attributed to clay and lignite concentration. Before new chemicals can be introduced into the Norwegian market, stringent environmental requirements must be met. The pre-existing viscosifying polymer used globally in clay-free systems is classified as “black” in Norway because of its inability to biodegrade, meaning it cannot be used. To address this, a polymer-based viscosifying agent has been developed to replace organophilic clay and serve as a much more environmentally acceptable substitute.

Influence of modified starches composition on their performance as fluid loss additives in invert-emulsion drilling fluids

The influx of the liquid phase of drilling fluid, known as filtrate, in oil and gas producing zones can cause a significant decrease in the relative permeability of the fluids in the reservoir, and consequently, the well’s productivity. The growing interest in developing non-aqueous fluids with low toxicity and good performance under extreme temperature and pressure conditions encourages research in this area. This study investigates the potential of using starch derivatives modified with vinyl esters from fatty acids, as additives to control filtrate in invert-emulsion (W/O) drilling fluids. There are no reports of the use of modified starches as additives to control filtrate in non-aqueous systems. The synthetic drilling fluids used in this study were prepared from a standard formulation, submitted to a dynamic aging process and evaluated by means of physical–chemical filtration tests at high temperature and pressure, along with electrical stability and rheological tests. The results indicate that the formulations developed from fatty esters from starch are able to compete technically with the standard drilling fluid, and the performance of these materials is associated with the degree of chemical modification of the polysaccharide.

High-Performance Water-Based Drilling Fluids Offshore Cameroon

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163502, ’High-Performance Water-Based Drilling Fluids: An Environmentally Friendly Fluid System Achieving Superior Shale Stabilization While Meeting Discharge Requirement Offshore Cameroon,’ by Anuradee Witthayapanyanon, SPE, Baker Hughes; Jerome Leleux, SPE, Julien Vuillemet, Ronan Morvan, and Andre Pomian, Perenco; and Alain Denax and Ronald Bland, SPE, Baker Hughes, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed. Historically, invert-emulsion drilling fluids are the preferred system for drilling offshore Cameroon. However, with a regulatory environment moving toward zero discharge, associated costs are rising. Therefore, an operator planning to drill in this environment investigated high-performance water-based-mud (HPWBM) -system alternatives. HPWBM systems offer the potential advantage of offshore discharge of drilled cuttings and effluents (owing to the absence of oil contamination) and lowered waste-management costs. Experience in the field demonstrated that the selected drilling fluid met expectations by achieving the required drilling performance and high shale stabilization with zero environmental impact. Introduction Drilling with an overbalanced pressure is a common operational technique used to prevent formation fluids or gas from entering the wellbore, thereby minimizing the risk of well kick and blowout. However, overbalanced drilling can cause drilling fluid to invade the formation, resulting in formation damage, differential sticking, and sloughing if the formation consists of highly reactive clay and shale. To avoid these consequences, invert-emulsion drilling fluids have always been preferable for drilling highly reactive clays and shale formations. The HPWBM system is formulated with a concept of total inhibition. Unlike a conventional water-based-mud system, designed chemical additives are used explicitly in the formulation to achieve desired drilling characteristics that are similar to those of invert-emulsion mud. The key features of HPWBM systems include high shale stability, clay and cuttings inhibition, rate-of-penetration (ROP) enhancement, minimized bit balling and accretion, torque and drag reduction, and environmental compliance. A complementary benefit of its aqueous base is that HPWBM captures the growing need for more-environmentally- friendly drilling fluids. During the past 10 years, more-stringent regulations on drilling-waste disposal have been implemented worldwide. The industry anticipates that the zero discharge of oil-contaminated drilling wastes will soon be the global standard. By switching from invert-emulsion drilling fluids (oil-/synthetic- based mud) to an HPWBM system, operators can achieve substantial cost savings on waste management and logistics. These savings result from the use of on-site, offshore discharge allowed by an absence of oil contamination.

Drilling With a Balanced-Activity Invert-Emulsion Fluid in Shale: Is It Sufficient for Maintaining or Enhancing Wellbore Stability?

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145969, ’Drilling With a Balanced-Activity Invert-Emulsion Fluid in Shale: Is It Sufficient for Maintaining or Enhancing Wellbore Stability?,’ by Terry Hemphill, SPE, Halliburton, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. Most wellbore-stability problems encountered while drilling occur in shale formations. Invert-emulsion fluids (IEFs) are used to drill reactive shales. Testing of a deepwater shale was performed with a new apparatus, which allows shale samples to be tested under downhole conditions. Results show that even at an activity level higher than the known shale-activity level, water was able to enter the shale and weaken it. The “chemomechanical-balance” concept was used to explain measured results in terms of the coupling of shale-mechanical properties and IEF chemical activity and to explain the resulting consequences of activity-level selection for IEF. Introduction The interaction of invert-emulsion drilling fluids with exposed shales has received much study because well-bore-stability problems occurring in shale are in the 80% range of all cases cited in literature. While usually not found in the reservoir sections, when these shales become unstable, significant nonproductive time is spent in efforts to stabilize the wellbore, and sometimes entire drilling intervals are lost. To understand the interaction of IEFs with shale during the drilling process better, it is helpful to review the pertinent theories used to describe such action. Semipermeable-Membrane Theory. At the face of the shale that is exposed to aqueous fluid, a semipermeable membrane exists that regulates the flow of water in or out of the specimen. Fluids having high membrane efficiencies, such as IEFs, have the ability to pull water from the rock efficiently. But fluids with low membrane efficiencies, such as common water-based drilling fluids, do not pull water efficiently. There is still uncertainty about whether the membrane is provided by the IEF or by the shale itself. Osmotic-Pressure Theory. Fluids having lower chemical activity compared with the shale-pore fluid can generate significant amounts of osmotic pressure that can be used to remove water from the rock. Conversely, an IEF with higher chemical activity in the drilling-fluid water phase than in the shale-pore water can push water into a shale.

Changing the Safe Drilling Window With Invert Emulsion Drilling Fluids

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132207, ’Changing the Safe Drilling Window With Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results,’ by Terry Hemphill, SPE, Halliburton; William Duran, SPE, Saudi Aramco; and Younane Abousleiman, SPE, Vinh Nguyen, SPE, Minh Tran, SPE, and Son Hoang, U. of Oklahoma, originally prepared for the 2010 CPS/SPE International Oil and Gas Conference and Exhibition in China, Beijing, 8-10 June. The paper has not been peer reviewed. Often the range in drilling-fluid densities required to prevent hole collapse without fracturing the wellbore (i.e., the safe drilling window) is narrow. This often is the case for wells having high deviation angles, and is of particular concern in extended-reach-drilling (ERD) wells. With increasing stepouts, the drilling equivalent circulating density (ECD) continues to climb with increasing measured depth (MD) while the true-vertical depth (TVD) remains fairly constant. Introduction The drilling of challenging wells often is characterized by a narrow safe drilling window, with the fracture-initiation pressure as the upper bound and the wellbore hole-collapse pressure as the lower bound. For those cases where the collapse pressures are below the pore pressure, the pore pressure then serves as the safe-drilling-window lower bound. The safe drilling window commonly is gauged in terms of equivalent mud weight (EMW) and represents the acceptable range of density for maintaining wellbore stability. When the wellbore is circulated, for example during drilling operations, the EMW is equivalent in value to the ECD. When the wellbore is static, the EMW is equivalent in value to the equivalent static density (ESD). Depending on the downhole pressure and temperature conditions, the ESD often is not equal to the density measured under ambient conditions, especially when drilling with invert-emulsion drilling fluids (IEFs). In the modeling of stresses around an intact wellbore, the safe drilling window becomes more narrow with increasing hole angle. Specifically, a deviated wellbore profile requires increased EMW to prevent collapse and reduced EMW to initiate fractures. Hence, in ERD wells, the safe drilling window can become very narrow at the higher angles of deviation. In the drilling of ERD wells having long departures, the ECD will continue to increase with increasing MD, as the frictional pressure produced while circulating increases with hole length while the TVD does not increase by much, if at all. The effect of ECD in these kinds of wells serves to increase the operating EMW to the point where the upper bound of the safe drilling window can be violated and initiation of wellbore fracturing is predicted. Consequently, much effort has been focused in recent years to widen the safe drilling window safely without sacrificing wellbore stability.

Application of Invert-Emulsion Drilling Fluid and Aqueous Completion Fluids for Long Multilateral Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 121905, "Design and Application of Invert-Emulsion Drilling and Aqueous Completion Fluids for Long Horizontal Multilateral Wells," by Alistair Hutton, SPE, Stephen Vickers, SPE, Marcus Davidson, SPE, and Jon Wharton, SPE, Baker Hughes; Andy Hatch, SPE, and Roger Simmonds, SPE, E.ON Ruhrgas UK North Sea Ltd.; and David Brankling, SPE, OCTL, originally prepared for the 2009 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 27-29 May. The paper has not been peer reviewed. The first dual-lateral well aimed at carboniferous reservoirs drilled in the UK southern North Sea was in the Rita gas field. This method enabled both the east and west fault segments of the field to be produced from the same upper wellbore, thus reducing drilling costs and improving field economics. An invert-emulsion drilling fluid was chosen for this field application because of the risk of shale instability over the long horizontal sections of each wellbore. Introduction The industry has experienced lower-than-expected production rates from wells that have been suspended for long periods with oil-based, solids-laden fluids before a cleanup has been initiated. This raised the question of what type of fluid to leave below the whipstock because re-entry to this leg for cleanup or well remediation was not economically feasible if production was lower than expected. Because of the diametrically opposed shape of the well, with long horizontal sections, the drilling team was strongly in favor of using an oil-based reservoir drill-in fluid (OBRDIF). This fluid would give a stable wellbore and provide a low friction coefficient for drilling and running the completion assemblies. Using OBRDIF would reduce the risk of hole instability and minimize non-productive time. However if OBRDIF was used in the drilling phase, it would mean that a solids-laden invert emulsion would be left in the hole when the first leg was suspended with the sand screens below the whipstock. This presented several risks. The fluid would require fine screening to prevent blocking the completion equipment with drill solids. Also, there was a risk that the solid particles in the suspension fluid would agglomerate as the fluid remained static for an extended period. If agglomeration did occur, these solids would probably not pass through the mesh of the completion screens and could potentially reduce screen conductance. The size and concentration of the solids in the suspension fluid were recognized as areas of concern that should be addressed to ensure maximum productivity of this well.

Technology Focus: Drilling and Completion Fluids (November 2009)

Technology Focus The success or failure of a well is a function of many factors. One important influence is the drilling fluid. As companies deal with drilling more-complex and -difficult wells, a well-designed drilling fluid can contribute to the success of the well. The year's highlights range from laboratory studies on fluid/chemical effects that relate to borehole stability to complex-fluid physical properties that mitigate lost returns. With ever-increasingly complex wells being drilled, the role of a drilling-fluid engineer has changed as well. When I started in the fluids industry 15 years ago, we were concerned mostly about controlling fluid loss, plastic viscosity, yield point, and gels. To meet today's challenging wells, we have to be educated about the aforementioned fundamental properties as well as borehole stability, narrow-margin drilling, and lost returns, in addition to environmental regulations and waste management. A good example is in the lost-returns arena. With the increasing understanding of rock mechanics, a more systematic approach to lost-returns remediation was developed. Only a few years ago, most people were unfamiliar with concepts such as "building stress or integrity" and terms such as "hoop stress," "stress cage," and "fracture-closure stress." No longer are the days of pumping "everything but the kitchen sink" down the hole in an often futile attempt to stop losses! Now, we take a science-based approach to fluids and engineer the particle sizes to stop lost returns and reach drilling objectives in less time and at a lower cost. The roles of fluids specialists working for operators and fluids companies are changing as well. They have become knowledgeable about more than just fluid makeup and properties. Companies have engineers and scientists on staff who research issues such as borehole stability, lost returns, waste management, and environmental regulations around the world. Please take time to read the following summaries as well as the suggested additional reading. Drilling and Completion Fluids additional reading available at OnePetro: www.onepetro.org SPE 120646 • "Quest for a Pragmatic Drilling-Fluid-Performance Index—Key to Improving Fluid Performance and Optimizing Quality-Well-Delivery Economics" by Peter Osode, SPE, Petroleum Development Oman, et al. SPE 123013 • "Changing Shale Strengths With Invert-Emulsion Drilling Fluids: Theory, Measurement, and Modeling" by T. Hemphill, Halliburton, et al. SPE 119269 • "Drilling-Fluid Design Prevents Lost Returns by Building Integrity Continuously While Drilling in East Texas" by Kenneth B. Vaczi, SPE, ExxonMobil, et al.

Correlation of Ultralow-Shear-Rate Viscosity and Dynamic Barite Sag

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 invertemulsion 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.

Anaerobic Biodegradability of Oil-Based Fluid for Invert-Emulsion Drilling Fluids

This article is a synopsis of paper SPE 39386, "Anaerobic Biodegradability of Oil-Base Fluid for Invert-Emulsion Drilling Fluids," by D. Blanchet, A. Audibert, SPE, and J-F. Argillier, SPE, Inst. Francais du Petrole, originally presented at the 1998 IADC/SPE Drilling Conference, Dallas, 3-5 March.