Colombian Underbalanced Drilling Operations - Start Up Experience

Rheological studies and numerical investigation of barite sag potential of drilling fluids with thermochemical fluid additive using computational fluid dynamics (CFD)

Potential Leakage Paths along Cement-formation Interfaces in Wellbores; Implications for CO2 Storage

In 2000–2001, an offshore survey and environmental assessment were conducted of drilling activities offshore Brunei (Adinin-Jacques Whitford1). A primary focus was to evaluate the environmental effects of disposal of oil based mud (OBM), ester-based synthetic mud (ESBM), and water based mud (WBM) in the tropical marine environment of the South China Sea. A number of well sites were surveyed for each of the mud types, encompassing varying water depths (20 – 500 m) and time elapsed since drilling. Key parameters (e.g., hydrocarbons, esters, metals and redox) were examined at all sampling locations, depending on the drilling muds used. Side-scan sonar, detailed hydrographic imaging, sea bed video, current information, and benthic sampling results were also interpreted. A modified radial sampling pattern was used. The study concluded that the magnitude and persistence of environmental effects from discharge of drilling muds and cuttings range, in order of severity, from OBM to ESBM to WBM. The study found that OBM and cuttings are toxic to marine life and can persist on the Brunei sea bed for over 13 years. Biophysical effects on the sea bed from both WBM and ESBM are similar, and result primarily from smothering of benthic organisms by sedimentation and anoxic conditions due to bacterial decomposition within the cuttings piles. WBM effects were, however, noted to be more widely dispersed (> 1200 m) and exhibited indications of faster benthos recovery (within 3 years) than ESBM (typically dispersed within 200 m). The survey results and detailed habitat sensitivity mapping were used to prepare comprehensive site-specific guidelines for WBM and ESBM disposal offshore Brunei. Using a "receiving environment" approach, the guidelines specify detailed instructions for WBM and ESBM offshore disposal in each of seven management areas ranked according to environmental sensitivity.

Laboratory tests using milled-tooth and diamond microbits compared drilling rates in water, water-base mud, oil-base mud, and specially formulated oil-base muds. The oil-base muds containing minimum colloidal material improved drilling rates with milled-tooth bits very little, but the improvement in drilling rates with diamond bits was substantial. Introduction Oil-base muds are disagreeable to use and expensive to prepare. Howeverfortunately for the drilling industrycertain things that cannot be accomplished with the current water-base systems can be carried out with oil-base muds. Most of the advantages of an oil-base mud become more important as wells are drilled deeper and deeper to find productive formations. Oil-base drilling fluids were first used to prevent damage to productive formations. These early oil-base fluids were simply viscous crude or refined oils. They were viscous in order to lift solids out of the hole and to limit the loss of the oil to the formation through seepage or filtration. Attempts were made to use calcium oxide to react with the water that inevitably became incorporated into the mud. Even at that early date, oil-base fluids had the reputation of slowing down the drilling. Later, oil-base muds were formulated with emulsifiers and surfactants to avoid water-wetting the solids. A moderate concentration of water could then be maintained for improved performance and lower cost. Oil-base muds (or invert emulsion's) did not achieve their current versatility, however, until oil-dispersible clays became available to prepare a low-viscosity mud having good suspension capabilities and filtration control at high temperature. This type of mud can give reasonable drilling rates in most situations, but in deep drilling the oil-base mud again slows drilling rates in low-permeability rock. Except for its effect on drilling rate, the oil-base mud is ideally suited for deep drilling. A good oil mud is more stable at high temperature than the best of the water-base systems. Salt sections and formations that contain water-reactive components can be drilled without difficulty. Hydrogen sulfide and carbon dioxide present neither a stability problem nor a corrosion problem when electrically problem nor a corrosion problem when electrically nonconductive oil-base mud is used. The water phase of the oil-base mud can be adjusted to prevent shale hydration and thus provide good hole conditions for the long periods required to dull a deep hole. All these advantages made it worthwhile to explore the possibility of improving the drilling rate of oil-base mud in rocks of low permeability. Background In 1958 Moore used laboratory drilling equipment to study the effect of apparent viscosity on drilling rate in Indiana limestone (approximately 10 md). He tested at a weight on bit of 1,000 lb, 60 rpm, 5 gal/min, and a differential pressure of 500 psi. He ran tests in a bentonite mud and in water to which glycerine had been added to increase its viscosity. He found that the viscosity created with either technique produced roughly the same effect on drilling rate. Following are some of his conclusions:A viscosity increase imparted to a liquid system by any means will tend to reduce drilling rate.There appear to be two logical reasons why viscosity slows down the rate of rock penetration: JPT P. 507

Traditional primary solids control methods use high energy, high G-force shakers to "shake" the fluid off the drilled solids on multiple static screens, and drilling fluid losses are typical 1 barrel of fluid for every 1 barrel of rock drilled. The new approach described in this paper replaces shakers with a vacuum-based system, to optimize the separation of drilling fluid and cuttings as they return from the wellbore. During this trial, a high-flow vacuum and rotating filterbelt (screen) system was configured to safely recover more drilling fluid from the cuttings, with the intention of reduce drilling waste. The goal is to validate the performance and HSE benefits of using vacuum-based primary solids control technology versus traditional shale shakers. Success criteria for the trial on two land wells were compared to common shale shaker performance and included: reduce fluid on cuttings by 30% (no more than 0.7 barrels of mud per 1 barrel of rock drilled); reduce screen consumption; and reduce noise level below that of the existing shale shakers. A third-party cuttings flowmeter was used to measure the rock recovered by the vacuum-based system. The following results were recorded during the trial on two wells: fluid-on-cuttings was only 29%, versus the 70% target for the trial; average filterbelt life exceeded the trial target by 54%; and sound pressure level was measured at 74 dBA, at least 3 dBA less than common shakers. Based on retort analyses, Oil On Cuttings averaged 8.39% wet weight. Total rock recovery for the vacuum-based system was 91% of the theoretical hole drilled. During the fluid/cutting separation process, the unit is operated as an enclosed system, eliminating operator exposure to harmful vapor and gases. Finally, it was noted that changing the filterbelt (screen) could be performed by one person in approximately 3 minutes. In conclusion, the trial demonstrated that 71% less drilling fluid was lost versus a typical shale shaker, at the same time reducing overall drilling waste volumes and providing a safer working environment for personnel. Vacuum-based primary solids control systems represent a step change in performance over the decades-old shale shaker concept. The production of significantly dryer cuttings can eliminate the need for traditional de-sanders, de-silters, centrifuges and cuttings dryers. In addition, benefits related to transportation, storage, and processing of drilling waste, can be dramatically obtained.

Ever evolving drilling performance requirements dictate bits drill wider ranges of lithologies while offering improved efficiency and reduced NPT. These performance requirements necessitate compatible drill bit technologies. As lithologies associated with these drilling objectives tend to be harder and more abrasive; the need for adaptable, durable, and efficient drill bit designs is intensified. With these challenging applications / objectives, Polycrystalline Diamond Compact (PDC) technologies are pushed to their material limits. These limits emerge as failures in PDC thermal fatigue, abrasion, and impact damage. Due to the absence of state-of-the-art drill bit material technologies compatible with achieving these drilling objectives, multiple trips are commonly required. Often, this translates into the use of non-PDC bits (Rolling Cutter and Impregnated) to complete challenging sections. As efficiency is hindered by bit type and increases in non-productivetime due to multiple bit trips, operators incur significant cost while drilling these intervals. New drill bit technology capable of drilling these lithologies and performance requirements is unmistakably needed. This paper describes the development of novel drill bit technology aimed at this requirement. This technology is born through the fusion of existing bit technologies; Fixed Cutter and Impregnated Diamond, and a unique design philosophy providing greater versatility in drilling a wider range of harsh lithologies, not typically drilled entirely with PDC bits. This novel design philosophy includes optimized cutter placement and exposure of diamond impregnated mix applied in critical areas of the bit. This project was initially targeted at the Sub-Saharan region in the Congo, where the existence of conglomeratic intervals still represents a challenge to reach TD in a single run for sections with high clonglomeratic percentage. In its first trial, the new technology hybrid bit drilled 300% more interval than the benchmark with 34% improvement in ROP, in comparable sections with similar conglomerate content. Subsequent runs have resulted in dramatic savings due to reduction of trips as well as improved ROP. This technology has provided the industry step change in performance and decrease in non-productive time.

The increasing number of horizontal wells being drilled, together with the continuing development and use of open hole completions has resulted in increasing reliance on formation damage testing to select the appropriate drilling fluid and/or cleanup technique. A two-year laboratory study was conducted to evaluate i) near wellbore invasion and related damage due to two typical Drill-In fluids (D.I.F.) and ii) performance of various cleanup procedures using specific "breakers". In the first part of the paper, values of Flow Initiation Pressure (F.I.P.) and return permeability measured on rock samples damaged with an Oil-Based Mud (OBM) and with a Water-Based Mud (WBM) are compared to evaluate the self cleaning properties of sandstone core samples having a large permeability contrast. In the second part, the performance of various "breakers" (mutual solvent, emulsified acid, surfactants for OBM, oxidizers and enzymes for WBM) is presented. Results show that the OBM present better filtration properties and is less damaging than the WBM. The general trend is that near wellbore return permeability (0–10 cm) and self cleaning properties are strongly related to the Jamming Ratio (Mean pore throat diameter/mean mud solids diameter). The use of OBM breakers may induce additional damage if the soaking time is not carefully controlled. On the other hand, WBM breakers may be efficient if they are used under optimum conditions. Finally, some recommendations are given for designing a low-damaging D.I.F. and to define, if necessary, the best cleanup procedure.

PreviousNext No AccessUnconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013High-Performance Water-Based Mud Using Nanoparticles for Shale ReservoirsAuthors: Chang Min JungRui ZhangMartin ChenevertMukul SharmaChang Min JungThe University of Texas at Austin;Search for more papers by this author, Rui ZhangChina University of Petroleum;Search for more papers by this author, Martin ChenevertThe University of Texas at AustinSearch for more papers by this author, and Mukul SharmaThe University of Texas at AustinSearch for more papers by this authorhttps://doi.org/10.1190/urtec2013-106 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract URTeC 1581549 Drilling through a shale formation can result in borehole instability problems, and this is known to add substantial costs to the operation. This is because conventional drilling fluids tend to interact with clay minerals in shales, and the mechanical properties of rock are changed by clay swelling. To avoid those problems, drilling fluid design is one of the most important factors that need to be considered. Oil-based muds (OBMs) are traditionally preferred due to their ability to minimize this interaction. However, OBMs are expensive and are subject to environmental constraints, so water-based muds (WBMs) are often preferred. To reduce the interaction between water-based muds and shales, we need to reduce water invasion into the shale. To reduce this invasion, internal or external filter cakes should be developed. Shale has extremely low permeability and a very small pore throat size, so normal mud cakes fail to stop or even reduce the fluid invasion. We have shown that the addition of nanoparticle additives to water-based drilling fluids can significantly reduce water invasion into shales. In this paper, we report results for shale permeability and pressure penetration though shales using different fluids: brine, base mud and nanoparticle based muds. To better define the effect of nanoparticles, we used different concentrations of nanoparticles in the mud. From the large reduction in permeability and the pressure response results, we clearly show that nanoparticles act as good shale inhibitors to ensure wellbore stability during drilling. Keywords: borehole geophysics, environmental, fluid, rock geophysics, permeabilityPermalink: https://doi.org/10.1190/urtec2013-106FiguresReferencesRelatedDetailsCited ByStabilizing Asmari Formation interlayer Shales using water-based mud containing biogenic silica oxide Nanoparticles synthesized.Journal of Natural Gas Science and Engineering, Vol. 134Intelligent materials in unconventional oil and gas recoveryLaponite: a promising nanomaterial to formulate high-performance water-based drilling fluids23 September 2020 | Petroleum Science, Vol. 135Improving the shale stability with nano-silica grafted with hyperbranched polyethyleneimine in water-based drilling fluidJournal of Natural Gas Science and EngineeringExperimental Quantification of Formation Damage Caused by the Cross-linked Gel in Tight Gas ReservoirsJournal of Natural Gas Science and EngineeringModification of the Vipulanandan rheological model with correlation for temperature and electrolyte effect on drilling mudsAdvanced Powder Technology, Vol. 31, No. 1Nanotechnology and global energy demand: challenges and prospects for a paradigm shift in the oil and gas industry24 August 2018 | Journal of Petroleum Exploration and Production Technology, Vol. 9, No. 2Nanoparticle-Stabilized Emulsions for Improved Mobility Control for Adverse-mobility Waterflooding11 April 2016 Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013ISSN (online):2159-6832Copyright: 2013 Pages: 1229 publication data© 2013 Published in electronic format with permission by the Society of Exploration Geophysicists, American Association of Petroleum Geologists, and Society of Petroleum EngineersPublisher:Unconventional Resources Technology ConferenceSociety of Exploration Geophysicists HistoryPublished: 26 Sep 2013 CITATION INFORMATION Chang Min Jung, Rui Zhang, Martin Chenevert, and Mukul Sharma, (2013), "High-Performance Water-Based Mud Using Nanoparticles for Shale Reservoirs," SEG Global Meeting Abstracts : 1038-1044. https://doi.org/10.1190/urtec2013-106 Plain-Language Summary Keywordsborehole geophysicsenvironmentalfluidrock geophysicspermeabilityPDF DownloadLoading ...

The design of a Pre-Salt well with open hole completion typically involves cementing the production casing to cover the entire saline section. This approach facilitates drilling through the entire reservoir with minimal overpressure while using a Water Based Mud that is compatible with logging, completion and acid stimulation. However, due to difficult ties in geological interpretation on a Itapu well, it became necessary to drill the carbonate section with exposed salt using oil-based mud, while preserving the original completion design. This represents an unprecedented development in the Brazilian pre-salt. This article discusses the formulation of the oil-based mud and a method for removing the filter cake from the wellbore. It also presents the wellbore diameter, measured at the end of drilling, and some indicators of the well cleanliness after the completion fluid swap, and the damage ratio assessed following the stimulation operation. The oil-based mud prevented dissolution of the salt rock in the region that was drilled with water-based mud and further down. The conditioning string was pulled out of the well after the displacement operation with brine and a surfactant pill, with a remarkable condition of cleanliness and without trace of oil-based mud adhered. Laboratory tests with the surfactant pill have shown that it is possible to minimize, or even remove, the organic layer of the filter cake created by the oil-based mud on the wellbore by the drilling. After the acid stimulation the carbonatic reservoir exhibited high injectivity and high flow capacity. This drilling operation on the Itapu field represents a paradigm shift because demonstrated, in certain scenarios, that it is possible not only to drill the reservoir phase with exposed salt, but also to do so with oil-based mud while removing the filter cake from the wellbore. This technique can make possible more ambitious projects on the Pre-Salt scenario, such as the development of mature Pre Salt fields with a high degree of depletion pressure on the reservoir.

Improper drilling fluid parameters may induce a variety of issues, including insufficient cuttings transport, limited solids suspension, poor hole cleaning, and excessive filtrate invasion to the formation. Controlled and optimized drilling fluids rheology is considered the key parameter to solve severe drilling problems encountered during drilling operations. Oil-based muds have numerous applications, but owing to some economic, environmental, and operational challenges, drilling companies are looking for new additives to enhance the characteristics of water-based muds for improved performance. However, the longer exposure of some WBM additives degrades them, which leads to insignificant mud characteristics. In this study, micro-sized naturally occurring agro-material namely cupressus cones powder (CCP) has been assessed as a potential additive in WBM for the first time to enhance the mud performance by improving its rheological and filtration properties. The objective of this study is to prepare a drilling fluid using abundantly available cupressus cones powder and investigate its effects on mud properties. The rheological and filtration characteristics of the drilling muds were determined based on API standards. A series of experiments have been performed to evaluate the impact of CCP loading on the rheology and fluid loss characteristics of drilling mud. The concentration of CCP was varied from 1 to 7 ppb. The findings of rheological characteristics demonstrated that altering the CCP loading enhanced the plastic viscosity, yield point, and gel strength of water-based drilling mud. The optimal concentration for PV was recorded in the range of 2–4 ppb, while the optimum value of YP was obtained at 6 ppb. Moreover, the temperature affected the viscosity and filtration of the mud, whereas the CCP containing muds were found salt resistant. The percent decrease in filtrate volume at 25, 121, and 150 °C was noted as 50, 59.6, and 62%, respectively. The effectiveness of the CCP was also observed from the SEM analysis. This study described the use of a locally available agro-waste material as a potential mud additive.

High resolution micro-resistivity imaging has been available in the logging while drilling (LWD) industry for the last 15 years in water-based mud (WBM) systems. However, the recent introduction of LWD ultrasonic technologies means that high-resolution images and associated analysis are now available for both WBM and oil-based mud (OBM) applications. This paper details the deployment of a 4¾-in. LWD ultrasonic imaging service in a mature offshore carbonate field, in Abu Dhabi, and the assessment of images in WBM with micro-resistivity image comparisons. The 4¾-in. ultrasonic service combines borehole size and shape measurements with high-resolution radius and reflection amplitude images. The LWD tool takes advantage of drill string rotation to make a 360-degree scan of the borehole with each transducer. The ultrasonic sensor uses four transducers that operate in a pulse-echo mode. By firing simultaneously, the transducers provide a total of 2,000 traveltime and reflection amplitude measurements each second, enabling the creation of high-resolution images, even at high-logging speeds. The images were used to evaluate the suitability of the LWD ultrasonic measurements to enhance reservoir understanding, along with azimuthal high-resolution resistivity image measurements in WBM applications. The ultrasonic tool was run in tandem with the resistivity imaging tool on a recent well where an inflow control device (ICD) had to be installed. The ultrasonic images showed excellent agreement with the high-resolution resistivity measurements, illustrating bedding, natural fractures, and sedimentological features. The resolution of the reflection amplitude images enables identification of drilling-induced features on the surface of the borehole, highlighting the measurement's value in understanding the impact of bottom hole assembly (BHA) design on the quality of the wellbore in fine detail. The travel-time measurements provide detailed evaluation of the borehole size and shape, with a three-dimensional (3D) visualization of the wellbore illustrating the ability of the tool to identify borehole enlargement and breakout. These findings demonstrate the suitability of the ultrasonic imager to address wellbore stability issues, identify principal stress orientations, and aid completion design in real time by confirming swell packer positions. Comparisons between ultrasonic images and established LWD technologies highlight the suitability of the radius and reflection amplitude images to provide enhanced reservoir characterization in both WBM and OBM applications. Log examples show that high-resolution images can identify bedding features, confirm natural fracture types and provide assessment of borehole size and shape for wellbore stability assessment for better ICD completion design.

High-quality borehole imaging is of great value during the evaluation of borehole conditions, such as wellbore stability, fracture identification, and dip mapping. Obtaining borehole images from logging-while-drilling (LWD) tools provides real-time information and allows access to highly deviated wells, which could be difficult to access using wireline tools. Borehole images can be acquired in water-based mud (WBM) systems with both resistivity and ultrasonic measurements. However, oil-based mud (OBM) systems limit the use of resistivity and pose great challenges to the ultrasonic method because of the high acoustic attenuation of the muds. This high attenuation can be overcome in wireline tools using larger ultrasonic transducers with representative dimensions of 2 in. diameter and 2 in. length. However, corresponding transducers intended for LWD tools, particularly for 4¾-in. collar sizes, should be smaller and sufficiently rugged to withstand the drilling environment. This paper describes a transducer developed by the authors to meet these output, size, and ruggedness constraints. The transducers have high acoustic output and low inherent noise to produce sufficient output to provide reliable imaging, even in heavy muds. Four of these transducers and associated electronics are integrated into an LWD tool. A real-time ringing removal algorithm was implemented to record low-noise echo waveforms in pulse-echo mode. These waveforms are then processed automatically to generate both time-of-flight and reflection amplitude measurements. The former can be used to gauge the borehole shape, while the latter characterizes the acoustic impedance and rugosity of the borehole wall, which, in turn, reveal fractures and formation bedding. During the development phase we conducted laboratory measurements to illustrate the high signal-to-noise ratio (SNR) of the transducer, which is vital when operating in the transmitting mode. We obtained satisfactory results that demonstrate high sensitivity and well-collimated directionality in receiving mode. During laboratory tests, the transducer was able to detect a 0.1-in. fracture in a cement block immersed in water. In addition, results from a prototype tool incorporating the transducers run in 9.5-lbm/gal OBM in a test well, which are comparable to wireline quality ultrasonic results, are discussed.

Shale-gas plays have gained significant importance in China. Sichuan Basin, industry's primary focus for shale gas, has finished hundreds of wells. The employed drilling fluids for drilling shale horizontal wells here are mostly oil-based muds (OBMs), due to its well-known excellent performance and the considerable geologic structural complexity. With the implementation of new national environmental law, the application of OBMs will be limited. A pressing goal is to develop a high-performance and environmental-friendly water-based mud. This paper discussed the research and application of a novel high-performance water-based mud for shale gas horizontal wells in Zhaotong area of Sichuan Basin. The morphology, mineralogical composition, Porosity and cation exchange capacity of the shale samples, and the key technical problems in the target formation were first analyzed. Then, a novel hybrid silicon shale inhibitor, rigid nano-polymer plugging agent, liquid filtrate loss control agent and liquid lubricator were prepared, respectively. Incorporated with other selected agents, an innovative water-based drilling fluid (HPWBD) with a density of 2.2 g/cm3 was formulated and applied. Extensive lab work was carried out to compare the properties of HPWBD with field oil-based drilling fluid. The results show that HPWBD had excellent inhibitive and lubricant properties, closing to the oil-based drilling fluid. Besides, HPWBD was highly plugging and rheology stable after rolling at 100 oC under high density conditions. Then, the HPWBD was applied successfully in Huangjinba YS108H4 well. The drilled horizontal well interval reached a length of about 1500 m. During drilling, no downhole troubles were observed, no bit balling was found, the borehole diameter was regular, and the electrical logging operation was successful just at the first time. Meanwhile, it reduced cost and environmental concerns associated with cuttings transportation and disposal. In a word, the developed high-density water-based drilling fluid showed outstanding performances, closed to oil-based muds. Moreover, it was beneficial to the environment and could reduce the cost significantly. It will provide an alternative to oil-based mud for safe and environmental development of shale gas in China.

Maurer Technology Inc. (MTI) formed a joint-industry partnership to fund the development of a hollow sphere dual-gradient drilling (DGD) system. Phase I consisted of collecting, compiling, analyzing, and distributing information and data regarding a new DGD system for use by the oil and gas industry. Near the end of Phase I, DOE provided funding to the project that was used to conduct a series of critical follow-on tests investigating sphere separation in weighted waterbase and oilbase muds. Drilling costs in deep water are high because seawater pressure on the ocean floor creates a situation where many strings of casing are required due to the relatively close spacing between fracture and pore pressure curves. Approximately $100 million have been spent during the past five years on DGD systems that place pumps on the seafloor to reduce these drilling problems by reducing the annulus fluid pressure at the bottom of the riser. BP estimates that a DGD system can save $9 million per well in the Thunderhorse Field and Conoco estimates it can save $5 to $15 million per well in its deepwater operations. Unfortunately, previous DGD development projects have been unsuccessful due to the high costs ($20 to $50 million) and reliability problems with seafloor pump systems. MTI has been developing a simple DGD system concept that would pump hollow glass spheres into the bottom of the riser to reduce density of the mud in the riser. This eliminates the requirement for seafloor pumps and replaces them with low cost mud pumps, shale shakers, and other oilfield equipment that can be operated on the rig by conventional crews. A $1.8 million Phase I joint-industry project funded by five service companies and three operators showed that hollow spheres could be pumped well, but difficulties were encountered in separating the spheres from a polymer mud supplied by Halliburton due to the high viscosity of this mud at the low shear rates encountered on oilfield shale shaker screens. As a result, an excessive amount of this polymer mud flowed across the screen with the beads instead of through the screen. At the completion of the Phase I project, it was concluded that the hollow sphere system would not work effectively with the polymer mud tested. ExxonMobil and Shell engineers proposed that additional sphere separation tests needed to be conducted with weighted oilfield waterbase and oilbase muds to determine if the DGD system would work with these muds. The DOE agreed to provide a $200,000 grant for these tests. The DOE-funded tests, described in this report, showed that the spheres could be pumped with conventional oilfield centrifugal and triplex mud pumps and separated effectively from both oilfield waterbase and oilbase muds using conventional oilfield shale shakers and hydrocyclones. As a result of the success of these DOE tests, this DGD system is ready for full-scale field testing, first on land wells and later in the offshore environment. Maurer Technology Inc. is currently proposing a Phase II project to oil companies to further develop this DGD concept. This project would be funded by four to eight operators. If Phase II tests are successful, Noble plans to commercialize this system with a service company partner that will market and operate the DGD system on Noble's and other drilling contractors' rigs.

Summary High-resolution acoustic borehole imaging is now available for LWD (logging while-drilling) operations where, previously, this was only available for wireline acquisition. As a stand-alone service, this opens up possibilities for high-resolution caliper visualisation of borehole shape, fracture characterisation in OBM (oil-based mud) and other geological interpretation. We show new applications from the stand-alone service and in combination with existing high-resolution electrical imaging LWD service, which is especially important for full fracture characterisation in water-based mud (WBM). Additionally, we explore further interpretation applications based on the different measurement physics from combined tool runs that are used to look for changes in rock properties and mineralogy.