Effects of the hydrophilic–lipophilic balance of inorganic nanoparticles on the properties of a non-aqueous drilling fluid with organo-palygorskite

Investigating lost circulation in DEA 13 JIP has shown that it is difficult to arrest losses while drilling with non-aqueous drilling fluids (NAF) as compared to aqueous drilling fluids (AF). In an earlier work (Kulkarni 2012), a novel method was discussed to characterize the plugging (of LCM particles and Fibers) performance of non-aqueous and aqueous drilling fluids using viscoelastic parameters under shear stress (First Normal Stress Difference=N1). This paper discusses the modification of drilling fluids (particularly non-aqueous fluids) to combat lost circulation. N1 measured at low and moderate shear stresses for different aqueous and non-aqueous drilling fluids shows that the magnitude of N1 for AF was significantly higher than that for NAF; although, the FANN® 35 viscometer shear rheology of both was similar. Another important finding was that adding certain polar-organic compounds to the NAF improves its N1 magnitude remarkably, which in turn was found to improve the drilling fluid's performance in lost circulation applications. For representative AF and NAFs, with the same FANN 35 viscometer rheology properties and lost circulation materials, fracture plugging efficiency was probed on a Permeability Plugging Apparatus (PPA) using a tapered slot. The plugging performance of the LCM in the AF was significantly better than in the NAF for the same combination of LCM. This difference in plugging performance was attributed to the noticeable difference in N1 observed for these two drilling fluids. The relation between N1 and plugging efficiency became evident when the addition of polar-organic compounds to the NAF increased its N1 and improved its plugging efficiency. These findings could be used to tailor the NAF for LCM treatment during the mud design phase and help alleviate trial-and-error in the LCM design.

Evaluation of polymer/bentonite synergy on the properties of aqueous drilling fluids for high-temperature and high-pressure oil wells

Drilling fluids are tested daily with many properties recorded to ensure that drilling operations are performed with the highest possible efficiency and in compliance with operator requirements. Mud check data are accumulated over the years but is heavily underutilised, as it is rarely used after the job is finished; this data are instrumental for optimization of future drilling fluids, however.The original global daily mud check data for ~30,000 wells (>780,000 individual checks) since 2016 is retrieved from the service company mud database. This large volume of data is prepared by selecting the key drilling parameters and fluid properties and performing the extensive cleaning to enable the usability of the data. It becomes evident that to make fluid profiling meaningful, just focusing on fluids properties is not enough, but the associated drilling parameters and conditions are critical for a meaningful analysis. The dataset is then evaluated using exploration data analyses and multidimensional statistical analysis techniques. An evolving barrel cost is calculated from product concentrations and product costs, which is then used to calculate the cost of dilution. This is combined with the costs of fluid treatment, circulation, and tripping to create a normalised cost of fluid use. By possessing a normalised cost of fluid use, a holistic cost model can be created an applied to future wells to better inform decisions on fluid selection.The clean dataset is comprised of more than 425,000 records with drilling parameters such as depths, hole size, bottomhole circulating temperature, and main drilling fluid properties, some being generic (e.g., rheology at different shear rates, fluid loss, and solids contents) and some specific for the fluid type, such as water-based mud (WBM) and nonaqueous fluid (NAF). As a part of the exploratory data analyses, all the attributes are evaluated by reviewing individual distributions, running pair-wise correlations, and performing cluster analysis to identify groups of highly correlated properties. The fluid types and families are then profiled using aggregated properties (5th, 50th, and 95th percentiles) and analysed for (dis)similarity between fluid types and families. Several dimensionality reduction techniques are also tested to visualise fluid similarities and cluster fluids by a multitude of properties.The developed analytics framework enables understanding of relationships between drilling fluid parameters and associated drilling properties, determines similarity of fluid systems in terms of key properties, and defines the fluid properties that are optimal or require adjustments for a set of drilling conditions. The paper explains how fluid profiles built on large-scale historical usage data enable new applications of fluid systems. To demonstrate the power of the fluid profiling approach, the analysis is performed for different geographical locations and drilling conditions. Examples also include product family similarity evaluation across fluid types, providing a path toward potential replacement of NAFs with similarity in properties but more cost effective and environmentally benign WBMs.The data analytics framework is developed and presented here, relying on hundreds of thousands of drilling fluid check records, cleaned and processed to enable data-driven decisions on drilling fluid type and family selection, and optimal fluid property ranges—improving drilling process efficiency.

Technology Focus When you take a look at the oil industry these days, what is the one thing you hear and read about the most? “Shale plays.” Operators are developing resources, purchasing acreage, and purchasing companies that have acreage in the USA and in countries around the world, now more than ever before. For long-term economic stability of these projects, they need to be drilled as inexpensively and as fast as possible—basically, they need to be “factory-type wells.” The main fluid-related challenges associated with shale drilling are rate of penetration (ROP), shale stability, torque and drag, and waste management. Many of these wells are being drilled with nonaqueous fluids (NAFs) to meet these challenges, with the only real issue being waste management. However, there are technologies being used that reduce the amount of waste generated with NAFs, such as premium solids-control systems and thermal-desorption methods. In an effort to eliminate NAF waste-management issues, drilling-fluids companies have developed fit-for-purpose water-based drilling fluids for each of the major shale plays. The shale regions around the world vary in depth, mineralogy, temperature, and other characteristics, and a single fluid formulation does not fit all circumstances. Each fluid is customized to the unique characteristics of a particular shale region. Fluids companies have specific products and chemistries that are designed for a specific type of shale and drilling operation. As technological advances enable exploitation of shale resources around the world, the challenge will be to find the most-cost-effective solution. As always, the lowest overall well cost may not result from the lowest-cost-per-barrel drilling fluid. One has to take into account ROP, torque and drag, wellbore stability, and waste management when determining the most-cost-effective solution. There were many good papers written this year, and I have tried to choose a variety of universal topics. Please take time to read them and the papers listed as additional reading. Drilling and Completion Fluids additional reading available at OnePetro: www.onepetro.org SPE 144214 • “Crude-Oil-Compatibility Method Significantly Minimizes Volumes Required” by Katrina Schultz, SPE, Baker Hughes, et al. SPE 142008 • “Chemical Properties Affecting the Environmental Performance of Synthetic-Based Drilling Fluids for the Gulf of Mexico” by P.B. Dorn, SPE, Shell, et al. SPE 139623 • “Drilling-Fluid Design Enlarges the Hydraulic Operating Windows of Managed-Pressure-Drilling Operations” by Doug Oakley, M-I Swaco, et al. SPE 139534 • “Preliminary Test Results of Nanobased Drilling Fluids for Oil- and Gasfield Application” by Md. Amanullah, SPE, Saudi Aramco, et al.

Technology Focus Nonaqueous drilling fluids have been used extensively by the industry, particularly in complex drilling scenarios. They carry some concerns, however, related to environmental issues and higher initial cost, potential for lost circulation, effect of pressure and temperature on drilling-fluid density, and capacity to solubilize natural gas compared with water-based drilling fluids [water-based mud (WBM)]. The latter three concerns have implications for well integrity. It is generally accepted that the risk of induced fracture (and consequent lost circulation) is greater when using non-aqueous fluids than when using WBM. The formation-breathing phenomenon is also more pronounced with nonaqueous drilling fluids compared with WBM. Nonaqueous drilling fluids are more sensitive to pressure and temperature changes than WBM is. Thus, the density and viscosity of these fluids inside the well are more difficult to establish, increasing uncertainties about bottomhole and casing-shoe pressures. Because they are more compressible, longer periods are expected for shut-in pressure stabilization, for response delay of drillpipe pressure after choke adjustment, and for flowback to stop after the mud pumps are shut off. The gas solubility in nonaqueous drilling fluids makes the kick indicators less pronounced for its detection and increases the risk of rapid gas evolution where the pressure inside the well drops below the bubblepoint pressure. However, the solubility properties of these fluids can lead to favorable conditions also: If pressure remains above the bubblepoint as the kick is circulated out of the well, there will be no free gas and, consequently, the magnitude of pressure will be smaller. Also, no free-gas migration will occur in static conditions. All these issues have been studied extensively, especially those related to change in fluid density and gas solubility. In the list of papers recommended for additional reading, two address gas-solubility aspects in nonaqueous drilling fluids. Recommended additional reading at OnePetro: www.onepetro.org. SPE 180039 Kick-Detection Capability of Oil-Based Muds in Well-Control Situations by Harald Linga, SINTEF Petroleum Research/DrillWell, et al. SPE 185470 Thermodynamic Behavior of Olefin and Methane Mixtures Applied to Synthetic-Drilling-Fluids Well Control by D.C. Marques, Consultant, et al. SPE 180292 Mathematical Modeling of Gas in Riser by Ulf Jakob Flø Aarsnes, IRIS/DrillWell, et al. SPE 181672 Multiphase Well-Control Analysis During Managed-Pressure-Drilling Operations by Z. Ma, The University of Texas at Austin, et al.

As the oil and gas drilling industry moves into more technically challenging environments [e.g., drilling ultradeep onshore/offshore wells under extremely high temperature (above 300°F) and pressure (mud specific gravity above 2.0)], companies increasingly come under pressure to stretch technology and improve drilling performance while continuously striving to reduce costs and meet the requirements of stricter environmental regulations. Significant reserves additions may be realized if the risks associated with drilling in such harsh conditions (e.g., pressure control, wellbore instability, lost-circulation, sour gas) can be managed effectively. Design and development of a new generation of drilling fluids able to fulfill all of the attributed functions (e.g., stabilize the wellbore, control formation pressure, transport the drilled cuttings, minimize the fluid loss, and not reduce formation productivity) under such extreme pressure and temperature conditions is one of the key requirements for unlocking these resources. Drilling fluids used under ultrahigh pressures and temperatures need to be thermally stable and able to retain their rheological properties. Traditionally, nonaqueous drilling fluids (NADFs) have been used under these extreme conditions. NADFs, however, have significantly high operational costs with an associated health, safety, and environmental risk. As a result, there has been an increasing demand from operators to use aqueous drilling fluids [water-based muds (WBMs)], which are known to be environmentally benign and relatively less expensive. The use of WBMs under extreme temperatures and pressures, however, faces several challenges, including the breakdown of polymers and other additives used as fluid-loss preventers and rheological stabilizers. Therefore, recent research has focused on design and development of WBM systems meeting the following specifications: - Use of sodium chloride (for barite-laden formulation) and sodium bromide (for barite-free formulation) as base brines to reduce the total solids content for optimal fluid properties and to maximize the quality of wireline logs - Ensure inhibition of reactive shale formations to maintain wellbore stability while drilling intermediate sections - Provide optimal and stable rheological properties for excellent hole cleaning and drilling performance The newly developed ultrahigh-temperature water-based systems used custom-made branched synthetic polymers that exhibit superior rheological properties and fluid-loss control as well as long-term stability above 400°F. These branched synthetic polymers are compatible with most oilfield brines and maintain excellent low-end rheology. Other formulations proposed the use of β-cyclodextrin polymer microspheres (β-CPMs) as an environmentally friendly ultrahigh-temperature filtration reducer. When the temperature rose above 160°C, a hydrothermal reaction occurred for β-CPMs, and, as a result, numerous micro- and nanosized carbon spheres formed, which bridged across micro- and nanopores within the filter cake and reduced the filter cake permeability effectively. Bentonite-hydrothermal carbon nanocomposites also are proposed as nonpolymer additives to solve the ultrahigh-temperature/-pressure challenge in water-based drilling fluid. The nanocomposites are synthesized by a simple hydrothermal reaction in which biomass starch and sodium bentonite are used as the precursor and template, respectively. Such formulations have shown favorable rheology and filtration properties after hot rolling at temperatures as high as 460°F. This section presents selected papers showing examples of design, development, and field applications of the new generation of WBM fluid technologies. Recommended additional reading at OnePetro: www.onepetro.org SPE 206444 - Successful Application of a New Generation of Clay-Inhibitor Polymers While Drilling a Deep Exploration Well in the Astrakhan Region by Petr Leonidovich Ryabtsev, Akros, et al. SPE 205539 - Improvement of Rheological and Filtration Properties of Water-Based Drilling Fluids Using Bentonite-Hydrothermal Carbon Nanocomposites Under Ultrahigh-Temperature and High-Pressure Conditions by Hanyi Zhong, China University of Petroleum East China, et al. SPE 209805 - The Utilization of Self-Crosslinkable Nanoparticles as a High-Temperature Plugging Agent in Water-Based Drilling Fluid by Ming Lei, University of Alberta, et al.

To optimize production from a key reservoir, obtaining a core sample with minimum fluid invasion and damage was necessary. In addition, operational nonproductive time (NPT) related to drilling challenges, such as interbedded formations of varying formation pressures, wellbore instability in the reactive, stressed shale sections, and hole cleaning concerns, needed to be mitigated. This paper describes the design of the drilling fluid and its performance in the field. After completion of the first dump flood water injection well drilled using an 80/20 conventional nonaqueous fluid (NAF) weighted with barite, low injectivity was observed, which led to acquiring cores to analyze permeability and porosity along with the change in mineralogy resulting from long exposure of the reservoir in the water zone. A 70/30 organophilic clay-free (OCF) NAF was selected to mitigate equivalent circulating density (ECD) risks and minimize damage. Proprietary software was used to customize the bridging design, which was verified during laboratory testing, and to help ensure adequate hole cleaning with the customized low-ECD fluid. The engineered OCF NAF contained no damaging materials, such as barite, asphaltic material, or organophilic clay. OCF NAFs are well suited to low-ECD drilling operations because they are more resistant to weighting material sag than conventional NAF systems of similar rheology. This is a product of the high gel strengths developed, even in low-rheology (low-ECD) fluids. Downhole pressure fluctuations are low because these gels are fragile and break easily. For the well in which this OCF NAF was used, drilling, coring, and logging operations were successfully completed without incident. Four cores were acquired with minimal damage compared to the previous wells resulting from the engineered design of the bridging material and fluid-loss control polymers. In addition, there was minimal erosion to these four cores, which was a result of the low-ECD fragile gel fluid used. The fluid-loss control properties of the fluid were also effective in strengthening the wellbore and eliminating differential stuck pipe tendencies that had been observed in previous wells. The fluid properties resulted in minimal ECD, and the OCF NAF displayed excellent suspension along with improved pressure management; no pressure spikes occurred while breaking circulation. There was no NPT related to wellbore instability or any of the drilling challenges previously identified. This unique organophilic clay-free and organolignite-free drilling and coring fluid relies on a specialized technology involving an interaction between the emulsifier package and the polymer additives in the fluid. This provides the behaviors needed for reliable weight material suspension and suitable hole cleaning properties in a low-ECD drilling fluid. Together with the appropriately designed bridging package, the OCF NAF provided a better understanding of the reservoir characteristics by delivering the core with minimal damage.

Over the years, the drilling fluids industry has focused on solving problems related to non-productive time, primarily wellbore stability and lost circulation. Today, drilling fluids have evolved into high technology fluids that maximize drilling efficiencies, overcome anticipated drilling risks, and provide a stable wellbore within budget. Drilling a single hole section to accommodate formations with different pore pressures, formations such as unstable shales and into a depleted sand reservoir under a high temperature environment can be very challenging. To promote wellbore stability, a higher fluid density is often required to balance the highest possible pore pressure and minimize the potential for any formation break-out due to prevailing in-situ stress conditions. Increased fluid density will lead to a higher differential pressure across the depleted reservoir layers, and hence, the risk of lost circulation will increase. The risks of formation stability and lost circulation therefore create greater challenges for the planning team in order to drill the depleted reservoir in a one-hole section. A novel approach of using polymeric nanoparticles (NPs) in the design of a non-aqueous drilling fluid with an optimized and selective range of pre-determined, sized bridging materials based on software modelling has been applied successfully at the Saqqara field in the shallow waters of the Gulf of Suez to eliminate or minimize the risks associated with drilling the depleted reservoirs. A case study is included, which was the main motivation for writing this paper. The case study covers two wells that were sidetracked and drilled successfully as 6-inch hole sections, penetrating the abnormally pressured formations with a relatively lower fluid density compared to data from offset wells and the subnormally depleted reservoirs, with up to 2,600 PSI overbalance with a bottom hole temperature (BHT) of up to 350° F. The effectiveness of the polymeric NPs can be attributed to unique characteristics such as a very high specific surface area of 33.7 m2/g, narrow particle size distribution (PSD) between 135 and 255 nm with a D50 value of 179 nm, and their deformable nature leading to effective sealing performance. The effect of these NPs on the properties of oil-based drilling fluids has been evaluated through a variety of experimental lab tests. Rheological properties at different temperatures and filtrate loss were measured to study the effect of the NPs on the base fluid. The study indicated that small concentrations of NPs could provide a better performance for the drilling fluid along with high temperature resistance. This work focused on the role of NPs in designing a smart drilling fluid with tailor-made rheological and filtration properties. The paper also briefly describes the operations and discusses the challenges related to drilling in depleted reservoirs and how new drilling fluid technology makes difficult wells possible to drill

Composition and Properties of Drilling and Completion Fluids

In the formulation of drilling fluids, different additives are used to optimize their rheological behavior and control the fluid loss throughout the drilling process. Surfactants, as one of these additives, play a vital role in sealing off the lost circulation zones and in controlling the rheological properties of the dispersions to meet the specification of the desired applications. This chapter is divided into three sections. The first section reviews the definition, functions, and properties of drilling fluids, bentonites and surfactants. The second section provides an overview on the main and recent research on utilization of surfactants in drilling fluid formulations. The last section describes an experimental work on the effect of cationic surfactant CTAB and anionic surfactant SDS on the performance of water based drilling fluid. Adding of CTAB surfactant to water-based drilling fluid reduced significantly its viscosity and shifted its rheological behavior from shear thinning fluid with a yield stress towards Newtonian behavior. On the other hand, the SDS surfactant was effective in modifying the rheological properties of water-based drilling fluid in the concentration range that corresponds to critical micelle concentration (CMC) and critical coagulation concentrations (CCC) of SDS.KeywordsWater-based drilling fluidBentoniteSurfactantsCTABSDSRheology

The drilling fluid must be designed through a comprehensive process to select the right additives, and then must passed through different API standard evaluation processes to ensure the quality. However, the contamination of the drilling fluid with the drilled cuttings caused a significant alteration in the drilling fluid and sealing properties of the drilling fluid. Therefore, many studies have been conducted to identify the effect of different cuttings on the drilling fluid properties. The current work emphasized on the impact of four different cuttings (quartz sandstone, Argillaceous sandstone, Siliceous claystone, and Kaolinitic claystone). The utilized cuttings in this work were selected carefully from different sandstone types to have varied clay content ranged from 0 to 70%. The selected cuttings were prepared and then characterized in term of their mineral composition and particle size distribution. In order to accomplish the objective of this work, the base mud contains zero cutting concentration, after that, an additional four drilling fluid samples were prepared by adding the prepared cuttings in two different concentrations include 5 wt.% and 10 wt.%. Several indispensable tests were conducted to investigate the impact of the added cutting on the rheological properties, filtration performance, filter cake properties, and other primary properties such as the drilling fluid density and pH. The results exhibited that the fluctuation of fluid properties was governed by two factors, one was the cutting concertation and the other was the clay content. Filter cake thickness showed high sensitivity at the low cutting concentration while the other properties were mostly in the acceptable range. On the other hand, at higher concentration, the results fall down into two clusters: cuttings with clay content ranging from 0 to 50% (quartz sandstone cuttings, Argillaceous sandstone, and Siliceous claystone) and cuttings with clay content higher than 50% (Kaolinitic claystone) as shown in details in the result section of this work. This works highlight the important of considering the cutting impact on the drilling fluid properties which ultimately impact the whole drilling operations.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 192735, “The Evolution of Nondamaging Fluid Design and Implementation Offshore Abu Dhabi,” by Catalin Ivan, SPE, ExxonMobil; Yousif Saleh Al Katheeri, Melanie Reichle, Khalid Akyabi, James Thomas Ryan, Sheldon Peter Anthony Seales, SPE, and Sigit Kustanto, SPE, ADNOC; Laurie Hayden, M-I SWACO; and Christoper Steele, SPE, ELKEM, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, 12–15 November, Abu Dhabi. The paper has not been peer reviewed. This paper covers the 7-year history of drilling-fluids application in a reservoir drilling campaign offshore Abu Dhabi, from the early use of a solids-free, brine-/water-based mud to the recent application of nondamaging, nonaqueous fluids (NAFs) with micronized acid-soluble ilmenite. The complete paper provides details about the integration of filter-cake breakers with various types of drilling fluids, from dormant drilling-fluid additives to delayed, pH- and temperature-activated breakers. The paper describes the steps taken to achieve these performance goals, including changes to the oil/water ratio (OWR), internal phase composition [heavier calcium briomide (CaBr2) instead of calcium chloride (CaCl2)], and a micronized, acid-soluble ilmenite as a•weighting agent. Development Highlights A key objective for the offshore Abu Dhabi project was to drill longer horizontal 8½-in. intervals while retaining zero-skin completions. This necessitated reducing the torque and drag and coefficients of friction (COF). Achieving these design criteria required developing a nondamaging, nonaqueous (NAF) drilling fluid complemented with a filter-cake-removal breaker system. Emphasis was placed on the design of an NAF that combined the desired properties of low rheological profile for equivalent-circulating-density (ECD) management, low COF, and nondamaging water-based-mud (WBM) formulation. Four different generations of breakers for water-based reservoir drill-in fluids (RDF) were developed and used before moving to nondamaging NAF. The NAF went through three iterations in addition to fine-tuning of the breaker package. Data related to well information, reservoir rock type, and completion type were gathered and analyzed. Fluid interaction and other studies were performed to determine suitable fluid type and formulation. Other factors taken into consideration included offset well data, drilling requirements, environmental considerations, logging requirements, and likely mud-damaging mechanisms. Extensive laboratory tests were conducted, some of which included compatibility of various fluids, return permeability, changes to the OWR, internal phase composition, and a micronized, acid-soluble ilmenite as a weighting agent. The breaker systems saw the same extent of refinement, from enzymes to delayed organic acid precursors and chelating agents, to evaluate the removal of the fluid filter cake by the breaker. Fluid formulations were evaluated and optimized. More than 80 extended-reach-drilling wells have been drilled using both water-based and nonaqueous RDFs, each with specially formulated breakers. These wells yielded learnings that contributed to the current design and formulations. Friction factors (FFs) obtained using RDF NAF proved to be much lower than those with RDF WBM. The lower FF enabled wells with longer horizontal sections to be drilled successfully and at significantly higher rates of penetration. Using micronized, acid-soluble ilmenite lowered ECD as compared with sized calcium carbonate. Additionally, the evolution of breaker formulations allowed for longer breakthrough time, which allowed for better coverage of the lateral, better removal of the filter cake, and, ultimately, enhanced production through improved inflow profiles. The end result of the continuous improvement in reservoir drilling fluid was an NAF that combined the desired properties of low rheological profile for ECD management and low COF, and was•nondamaging.

Organophilic clays are widely used in non-aqueousdrilling fluids, mixtures of different components being used in a well bore. As bentonite claysare not naturally organophilic, they can be modified by specific treatments with surfactants (ionic or nonionic). Recent studies demonstrate the influence of clay, surfactant,and the presence of a dispersant in the rheology of fluids. In this study we verified the influence of clay, and surfactant in the production of organophilic clays using an alcoholic route for the rheology of non-aqueous fluids.As such, we performed the characterization of organophilic clays by X-ray diffraction (XRD),these non-aqueous fluids were produced according to Petrobras norms for rheological testing. The results evidenced influences of the clay / surfactant ratio on the rheology of non-aqueous drilling fluids.

Industry successful cases and lessons learned have shown the challenges of setting cement plugs in open hole. Using industry best practices, it is possible to successfully set cement plugs in deepwater HPHT wells drilled with non-aqueous fluids. However, it is not uncommon to see cases where a single cement plug job has to be repeated more than once in order to achieve a competent barrier. Among different reasons that would cause a cement plug to fail, are: contamination with non-aqueous drilling fluid, insufficient cement and spacer volumes, density hierarchy, friction pressure hierarchy and cement plug slumping. These challenges become more critical as offshore drilling moves towards new frontiers: deepwater, salt formations, deeper measured depth reaching higher bottom hole temperatures and pressures. In Brazil, drilling operators do not face one single challenge in their operations; they are facing a combination of them in most of the new wells. A successful case will be discussed, which describes the placement of a cement plug isolating an over-pressured gas reservoir and allowing the plug and abandonment operation to continue on a HPHT pre-salt offshore well in Santos Basin, in Brazil. The bottom hole pressure was over 137.8 MPa [20,000 psi] (ultra-high pressure well) and bottom hole temperature 171 degC [340 degF], required 2300 kg/m3 [19.2 lbm/gal] mud weight to maintain the well overbalanced after a gas influx happened when the mud had only a density of 2230 kg/m3 [18.6 lbm/gal]. In addition, the heavy-weight and non-aqueous fluid (NAF) added an extra challenge to this operation. On this case, high density, high performance system (HDHPS) with engineered particle size distribution (PSD) was the selected cement slurry in order to overcome ultra-high formation pressure. Special chemistry was combined to the HDHPS to place the cement plug across the gas reservoir and salt formation, maintaining its stability and assuring isolation of the gas in the reservoir. The cement plug placement was designed with dedicated cement plug placement software, which brought a superior value in analyzing the risks involved, determining the placement technique and confirming best practices, thus aiding to define the pre-job conditions and consequently assuring the success of the P&A. These practices can be successfully extended to other operators plugging and abandoning their wells in deepwater, HPHT wells and even in conventional environments. Introduction Placing cement plugs for sidetrack, remedial work, temporary or permanent abandonment is the highest cement activity offshore. It presents many challenges, including well cleaning, mud removal, minimizing contamination, cement slurry slumping, wait-on-cement sufficient time and more (Bogaerts et al. 2012). By adding to this condition a high pressure reservoir with high density drilling fluid to control the well and maintain it overbalanced, a set of new challenges are introduced to the cement job design and execution. In the following paragraphs the reader will understand why HPHT offshore wells present new challenges for placing successful cement plugs, as well see a thorough discussion on the design, execution and evaluation (DEE) on setting the first cement plug, responsible for isolating the gas reservoir, in the plug and abandonment (P&A) operations of the well 1-OGX-63-SPS drilled in Santos Basin, offshore Brazil.

Technology Focus It is no secret that drilling fluid is crucial in drilling operations. The main function of drilling fluids is to transport drill cuttings from the bottom of the hole up to the surface. Drill cuttings then will be separated on the surface before the fluid is recycled for further drilling. This is to ensure a smooth drilling operation. A drilling-fluids rheological study is a must when drilling a well. Mud engineers and drilling engineers work hand-in-hand to ensure the desired drilling fluid with the right rheological properties is achieved on the basis of reservoir requirements and conditions such as reservoir pore pressure and temperature. Numerous additives are included in drilling fluids to fine-tune the drilling-fluid properties. Such additives include barites for weighting, lime, caustic soda, soda ash, and bicarbonate of soda, as well as other common acids and bases for pH control, amine- or phosphate-based products, and other specially formulated chemicals for corrosion control. In addition, nanofluid also has been introduced to drilling fluid to improve drilling-fluid rheological properties further. Some researchers have worked on nanofluids-enhanced water-based mud prepared using the nanofluids of copper oxide and zinc oxide (sizes of less than 50 nm) in a xanthan-gum aqueous solution as a base fluid. The formulated drilling fluid showed improved thermal and electrical properties by approximately 35% compared with conventional water-based mud. Furthermore, numerous researchers also have studied the application of graphene in drilling fluids. The addition of graphene in drilling fluids improves drilling-fluid properties, specifically with regard to fluid filtration. Graphene-based drilling fluid seems to produce thin, firm, and impermeable mudcake. This, in turn, minimizes the invasion of fluid from wellbore to reservoir rock and minimizes formation damage. Graphene, however, is an expensive additive; 50 g of graphene is approximately $250. Thus, the real challenge is to source graphene from “unwanted” graphite-related waste. In this column, I have highlighted three papers with different novel ideas. One paper discusses the use of a novel polymer over conventional clay as a viscosifier and filtration-control agent. Another paper presents the lesson learned from high-temperature water-based mud offshore Sarawak. The last paper discusses a novel modified rectorite that provides reliable rheology and suspendabilty for biodiesel-based drilling fluids. I hope you enjoy and benefit from the selected and highlighted papers. Other interesting papers are on the recommended additional reading list and in the OnePetro online library. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 189344 Drilling Fluids Automix by Vidar Hestad, Cameron, et al. SPE 186233 Design and Application of Aerated and Foam Drilling Fluid, Case Study in Drilling Operations in Indonesia by WA Nugroho, Pertamina, et al. SPE 187135 Dry Liquids on Silica as Secondary Emulsifiers for Drilling-Mud Applications by V. Lifton, Evonik, et al.