Formation drillability is one of the most important aspects for planning and designing a new oil/gas well since the factors affecting the drilling performance have complex relationships between formation properties, drill bit design and operational parameters. In view of the high operating cost of drilling rigs, if Rate of Penetration (ROP) can be enhanced, it will reduce open-hole formation exposure time and complications associated with it, resulting in significant savings in drilling time and cost can be realized. Normally bit engineers utilize the assumed lithology from mud logs and detailed depth-wise lithology of offset wells. The lithology can also be interpreted from conventional logging data such as Sonic, Gamma and Density. Furthermore, the rock's compressive strength is calculated using Compressional / Shear travel time (Sonic log), Bulk density (Density log) and Shale content (Gamma log). These utilized tools to detect the lithology and rock mechanical properties have an extent of uncertainty due to effects either related to the borehole or drilling fluids that require extensive corrections. That degree of uncertainty subsequently can affect the drill bit design criteria, selection and viability of performance-enhancing features. This present paper reveals a new practical approach as a solution to minimize uncertainty in terms of bit design and selection by utilizing wellbore imaging either LWD and/or Wireline borehole images and lithology & mineralogy from either wireline mineralogy logs "Pulsed Neutron" and/or ROQSACN instrument to precisely deliver an accurate input data to the drill bit design/selection software modules.

Mud loggers are the first (and sadly in some cases the only) people to look at the cuttings. To actually see what the rocks look like, feel like, occasionally even taste. Most people looking at a well will actually look at "wriggly lines" or at best the cuttings descriptions from the loggers or geologist, two or three lines of abbreviations "claystone, light grey to grey, soft to firm, occasionally hard, slightly calcareous, trace fine sand". We have all read them, many of us have written them. These descriptions are incredibly useful and valuable, they are often all we have to understand the actual rocks and geology, especially with older wells. But in a world where we now enter the description and draw the logs with a computer, this information still comes from the subjective view of the logging geologist peering through a microscope In recent years, several tools have been developed to analyze drill cuttings from oil and gas wells. The most commonly used tools include X-ray fluorescence (XRF), X-ray diffraction (XRD), scanning electron microscopy (SEM) combined with energy dispersive X-ray spectroscopy (EDX), bulk density, and pyrolysis. Although each of these tools can be used to develop a limited determination of the in-situ rock character, the combination of three of these tools (XRF, SEM/EDX, and pyrolysis) can provide a more comprehensive picture of formation properties.The combination of XRF analysis with the SEM/EDX analysis is the key to the cuttings workflow. The exact location within the borehole can be determined and a robust mineralogy developed that is independent of normative mineralogy (typical XRF) or operator-interpretive mineralogy (XRD). Additional outputs include relative brittleness index, bulk density, lithology, fractional and textural relationships, total organic carbon (TOC) proxy, and a new porosity index. Trace and major elemental ratios are also available for precise stratigraphic placement. The addition of cuttings pyrolysis enables hydrocarbon typing, producible hydrocarbons, TOC, and total inorganic carbon (TIC) within each sample to be established.Chemical Lithostratigraphy uses whole rock inorganic geochemical (elemental) data, to give information on: Extrabasinal source area dominance and origin (volcanic, metamorphics, igneous, sedimentary), Extrabasinal component weathering or diagenesis (cementation) Intrabasinal components (Palaeoenvironment and insitu origin of sediments) Chemical Lithostratigraphy analysis of cuttings can be done application of automated mineralogical analysis of cuttings samples pre-drilling in defining stratigratic zones via mineralogy/elemental data. And then explore the application of the same data to assist, and in this case lead, the decision making process during directional drilling of the lateral well. The paper will also look at the use of the technology in defining tactical fracc-ing zone based on rock properties (e.g. ductility) determined from the mineralogical, elemental and textural data.This paper will show that through the use of automat...

Drilling and completing reservoirs without inducing measureable skin damage is rare. Frequently, drilling fluids impact a reservoir's flow potential while drilling as the rock matrix is invaded by solids and chemicals designed to enhance drilling performance. Drilling fluid can also cause formation damage if they are not properly removed during the displacement phase. These solids can migrate to the perforating zone and cause damage. Completion fluid designs governed by density for well control also often contribute to skin damage. Hydrocarbon flow may be impeded by damage caused by residual drilling debris or incompatible completion and workover fluids, in-situ emulsions, water block, organic deposition, or oily residue. Specialized surfactant systems have been developed to remediate near-wellbore damage caused by drilling and completion fluids, and damage induced by failed remediation attempts. The properties of these treatment systems include their ability to solubilize oil and, due to a significant reduction in interfacial tension between the organic and aqueous phases, effectively diffuse through the damaged zone to free up flow-resistant obstructions. The inherent properties of these systems make them ideal for removing induced formation damage as well as an excellent option for displacing synthetic or oil-based mud (S/OBM) from casing prior to the completion phase. In open-hole (OH) completions, specialized surfactant designs have proven very effective in removing S/OBM filter cake damage. In cased-hole (CH) completions, they have demonstrated a high degree of efficiency to clean damaged perforations.This paper presents a technical overview of surfactant systems for OH and CH remediation operations. The testing to qualify these fluids for the removal of damage and field results are presented that show the efficacy of these specialized surfactant systems to remove damage caused by OBM filter cakes and other oily debris to improve hydrocarbon recovery while addressing the operational challenges associated with these jobs. Introduction Avoidance of formation damage is a major attention when planning fluid systems for reservoir drilling and completion projects. 1-3 From a fluids standpoint, special emphasis is placed on developing systems that impart minimal damage to the rock matrix and leave the wellbore as clean as possible. The three primary cleaning activities target: (1) casing displacement cleanout, (2) filter cake removal in OH completions that use sand control techniques and (3) the clean-out of perforation tunnels in the near-wellbore region.Major improvements in OBM reservoir drill-in fluid design for OH completions have been made in recent years 4 ; however, in most operations, damage still exists. Other than poorly designed drill-in fluids, other major factors influencing the degree of residual damage from OBM include variations in reservoir quality, permeability, pore-size distribution, lithology, reservoir depletion and the complexity of the completion.In conventional completions, such as in sta...

Nanotechnology has become the buzz word of the decade! The precise manipulation and control a matter at dimensions of (1 – 100) nanometers have revolutionized many industries including the oil and gas industry. Nanotechnology applications have pierced through different petroleum disciplines from exploration, reservoir, drilling, completion, production, processing and finally to refining. Nanoparticles are the simplest form of the structures with sizes in the nm range. In principle, any collection of atoms bonded together with a structural radius of less than 100 nm can be considered a nanoparticle. The Tiny nature of nanoparticles results in some useful characteristics, such as an increased surface area to which other materials can bond in ways that make for stronger or more lightweight materials. At the nanoscale; size does matter when it comes to how molecules react to and bond with each other. The filter cake developed during nanoparticles-based drilling fluid filtration is very thin, which implies high potential for reducing the differential pressure sticking problem and formation damage while drilling. While drilling shales formations with nanodarcy (nD) permeability, Nanoparticles can be added to the drilling fluids to minimize shale permeability through physically plugging the nanosized pores and suppress the pressure transmission, hence Nanotechnology can provide a potential solution for environmentally sensitive areas where oil-based mud (OBM) historically used as a solution to stabilize shales. Geotechnical challenges normally increase with increasing well inclination due to the highly faulted nature of many of the formations. Pressures and temperatures are typically not excessive but the complex interlayering of shales, sandstones siltstones and limestones results in multiple problems associated with borehole instability. The Paper will reveal all lab work and field procedures for new Nanotechnology additive for wells that have an intercalated lithologies and tight reservoirs. Also paper will reveal the effectiveness of the nanotechnology additives to stabilize hole geometry that is demonstrated by comparison pre-nanotechnology wells and post-nanotechnology wells

Geomechanical modeling is a key driver in attaining optimum wellbore stability while drilling horizontal wells in the orientation of the minimum horizontal stress (Shmin). Although geomechanical modeling remarkably helped to obtain best estimates on minimum required mud weights for ensuring stable wellbore, these models still have uncertainties along the horizontal wellbores. Multiple factors contribute to wellbore instability such as lateral changes in rock mechanical and strength properties, formation pressure, and localized digenetic effects. An improved geomechanical workflow has been developed to manage uncertainties and enhance operational efficiency. The proposed methodology is composed of calibrated geomechanical models for wellbore stability assessment that to be applied for upcoming planned wells during drilling operations. A number of key parameters were identified to build customizable geomechanical solutions and deliver stable wells. These key parameters include occurrence and sequence of strong/weak formation intervals and risk of differential sticking across depleted intervals. Each plan well requires a solution that includes computation of minimum required mud weight, formulation of mud system to handle multiple failure mechanisms, design of Logging-While-Drilling (LWD) Bottom Hole Assembly (BHA), and real-time geomechanical monitoring. Upon implementation of this methodology, the horizontal well was drilled successfully in a controlled manner. In this paper, an experience is highlighted to demonstrate the effectiveness of customized geomechanical solutions. It discusses the implementation of geomechanics at a specific sub-surface condition to attain the best result. In this study, there was a high risk for wellbore instability while drilling through highly stressed formation in minimum stress direction. The task was approached in a systematic way with a core objective of ensuring practical implementation of geomechanics findings, and follow the recommendations to mitigate wellbore stability related issues. There were two options that were been evaluated in this paper to prevent and mitigate wellbore stability, the first one is to low mud weights together with wellbore surveillance using real-time technolog, the second on is to use higher mud weights using sealing polymer and proper mud system formulation to avoid differential sticking.