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Directional drilling is defined as the practice of controlling the direction and deviation of a wellbore to a predetermined underground target or location. This section describes why directional drilling is required, the sort of well paths that are used, and the tools and methods employed to drill those wells. Field developments, particularly offshore and in the Arctic, involve drilling an optimum number of wells from a single platform or artificial island. Directional drilling has helped by greatly reducing the costs and environmental impact of this application. A well is directionally drilled to reach a producing zone that is otherwise inaccessible with normal vertical-drilling practices.
The drilling conditions described above have led to the following practices, which are reasonably uniform, in the geothermal drilling industry. Bits Because of the hard, fractured formations, roller-cone bits with tungsten-carbide inserts are almost universally used for geothermal drilling. The abrasive rocks mean that bit life is usually low (50 to 100 m), but many bits are also pulled because of bearing failures caused by rough drilling and high temperature. Polycrystalline diamond compact (PDC) bits have the dual advantages of more efficient rock cutting and no moving parts, but experience with PDC bits in geothermal drilling is both scant and unfavorable. Much research and development in hard-rock PDC bits is under way,  so it is possible that these bits will come into wider use in geothermal drilling.
Penman, Andrew (Halliburton) | Wong, Siong Ming (Halliburton) | Cooper, Paul (Halliburton) | Fares, Wael (Halliburton) | Parker, Tim (Halliburton) | Goraya, Yassar (ADNOC OFFSHORE) | Alfelasi, Ali Saeed (ADNOC OFFSHORE) | Khemissa, Hocine (ADNOC OFFSHORE) | Al Dhafari, Bader Mohamed (ADNOC OFFSHORE) | Khaled, Islam (ADNOC OFFSHORE) | Ashraf, Muhammad (ADNOC OFFSHORE) | Al-Mutwali, Omar (ADNOC OFFSHORE) | Okuzawa, Takeru (ADNOC OFFSHORE)
Abstract A detailed visualization of borehole size and shape, both while drilling and prior to running casing, completions, or wireline logging equipment, is an essential requirement to minimize non-productive time (NPT) associated with poor borehole quality or wellbore stability issues. The required visualization is made possible using logging-while-drilling (LWD) high-resolution ultrasonic imaging technology, suitable for both water-based mud (WBM) and oil-based mud (OBM) systems. This paper provides borehole size and shape assessment from field deployments of a 4¾-in. ultrasonic calliper and imaging tool, illustrating the impact on borehole quality of various bottom-hole assembly (BHA) designs, including positive displacement mud motors (PDMs) and rotary steerable systems (RSS). The visualization of borehole quality enables features such as borehole spiralling and enlargement to be assessed and used as input into optimizing completions planning and formation-evaluation programs. In addition, the combination of high-resolution travel-time and reflection-amplitude images enables artefacts induced by drilling equipment, including RSS, to be identified and understood. High-resolution travel-time and reflection-amplitude images and 3D borehole profile plots are presented from multiple wells, showing how different drilling systems and logging parameters, including drillstring rotation and logging speeds, impact borehole quality. The relationship between the angular bend in the PDM and the impact it has on borehole spiralling is discussed. The LWD logs presented illustrate the factors that influence borehole quality and the methodology used to ensure that high-resolution images are available in both vertical and high-inclination wellbores, leading to the ability to reduce the NPT associated with wellbore stability issues. The observation and assessment of drilling artefacts and irregular borehole size and shape act as inputs into optimizing completion and logging programs, evaluating the optimal placement of packers and other completion equipment, and the design of the drill bit and BHA. The ability to collect high-resolution travel-time and reflection-amplitude ultrasonic images in both WBM and OBM, in wellbores ranging from 5¾ to 7¼-in., leads to significant improvements in the understanding of wellbore quality. Borehole size and shape can now be visualized in real time in either water or oil-based drilling fluids at a resolution capable of identifying all significant drilling-induced geometric artifacts. This allows the adjustment of drilling parameters to minimize NPT associated with common drilling hazards, the optimization of completion programs and wireline logging programs.
Bhimpalli, Sarah (ONGC) | Shinde, Ashok (Baker Hughes) | Rao, Bayye L (ONGC) | Perumalla, Satya (Baker Hughes) | Panchakarla, Anjana (Baker Hughes) | Chakrabarti, Prajit (Baker Hughes) | Saha, Sankhajit (Baker Hughes)
Abstract Geomechanics has an important role in assessing formation integrity during well construction and completion. It also has its effect when the wellbore is in production mode. Geomechanical study evaluate the impact of the present day in-situ stress and related mechanical processes on reservoir management. The study field ‘K' belongs to Plio-Pleistocene sequence of deep-water environment with hydrocarbon prospects. This belongs to Post-Rift tectonic stage of evolution with hydrocarbon occurring in structurally controlled traps. As a part of exploration activity, four offset oil wells were drilled earlier which were considered for the geomechanical model construction. Field (K) development plan comprising of six hydrocarbon producers and four water injectors was prepared. Considering the thick water column (300m-650m) in this deep water area of offshore and young unconsolidated sedimentary sequence in the sub-surface, expected pore-pressures can be high whereas the fracture gradient can be low. As a result, the safe drilling mud window can be narrow. Upon successful drilling of a well in such challenging environment without NPT (Non-Productive time), completing the well with best possible technologies suitable to the reservoir's mechanical behavior is utmost important for maximizing the production and minimizing the risk. To mitigate these problems in developing this field, an integrated reservoir geomechanics approach is adopted to optimize the drilling plan and reservoir completion parameters for the planned well. This paper covers the geomechanical study of four wells namely W, X, Y & Z drilled in the field ‘K'. The principal constituents of the geomechanical model are in-situ stresses, pore pressure and the rock mechanical properties. Geomechanical model for the field ‘K' was built utilizing the available data by integrating drilling, geology, petrophysics and reservoir data. Methodology adopted in this paper also highlights how a reliable geomechanical model can be built for a field, which is having data constraints. Constraining of stress magnitudes, orientation and anisotropy added value for efficient well planning in deep waters reservoirs. Calculating well specific reservoir rock mechanical properties, it made possible to identify the most optimal completion strategy. Approach contributed knowledge of geomechanical parameters based on the data of four offset wells has been used for successfully drilling and completion of all the subsequent wells without major challenges. Overall, geomechanical modeling has played a major role in drillability and deliverability of the reservoir. Integrated approach adopted in this paper can be used for well planning and drilling of future wells in East Coast of India with similar geological set up.
Abstract Flow assurance is a vital challenge that affects the viability of an asset in all oil producing environments. A proper understanding of asphaltene precipitation leading to deposition lends itself to reliable completions planning and timely remediation efforts. This ultimately dictates the production life of the reservoir. The Wireline Formation Tester (WFT) has traditionally aided the understanding of asphaltene composition in reservoir fluids through the collection of pressurized fluid samples. Moreover, the use of Downhole Fluid Analysis (DFA) during a fluid pumpout has augmented the understanding of soluble asphaltenes under in-situ flowing conditions. However, an accurate and representative measurement of Asphaltene Onset Pressure (AOP) has eluded the industry. Traditionally, this measurement has been determined post-acquisition through different laboratory techniques performed on a restored fluid sample. Although sound, there are inherent challenges that affect the quality of the results. These challenges primarily include the need to restore samples to reservoir conditions, maintaining samples at equilibrium composition, and the destruction of fluid samples through inadvertent asphaltene precipitation during transporting and handling. Hence, there is a need for WFT operations to deliver a source of reliable analysis, particularly in high-pressure/high-temperature (HP/HT) reservoirs, to avoid costly miscalculations. A premiere industry method to determine AOP under in-situ producible conditions is presented. Demonstrated in a Gulf of Mexico (GOM) reservoir, this novel technique mimics the gravimetric and light scattering methods, where a fluid sample is isothermally depressurized from initial reservoir pressure; simultaneously, DFA monitors asphaltene precipitation from solution and a high-precision pressure gauge records the onset of asphaltene precipitation. This measurement is provided continuously and in real time. An added advantage is that experiments are performed individually after obtaining a pressurized sample in distinct oil zones. Therefore, the execution of this downhole AOP experiment is independent of an already captured fluid sample and does not impact the quality of any later laboratory-based analysis. Once the measurements are obtained, these can be utilized in flow assurance modeling methods to describe asphaltene precipitation kinetics, and continuity of complex reservoirs. For the first time in literature, this study applies these modeling methods in combination with the AOP data acquired from a downhole WFT This approach has the potential to create a step change in reservoir analysis by providing AOP at the sand-face, along with insight that describe performance from asphaltene precipitation. The results of which have tremendous economic implications on production planning.
Abstract A new, through-the-bit, ultra-slim wireline borehole-imaging tool for use in oil-based mud provides photorealistic images. The imager is designed to be conveyed through drill-pipe. At the desired well section, it exits the drill pipe through a portal drill bit and starts the logging. Field test measurements in several horizontal, unconventional wells in North America show images of fine detail with a large amount of geological information and high value for well development. A relatively new solution for conveying tools to the deepest point of a high angle or horizontal wells uses a drill bit with a portal hole at the bit face. As soon as the bit reaches the total depth, a string of logging tools is pumped down through the drill pipe. The tools exit the bit through the portal hole, arriving in the open hole and are ready for the up log. The tools operate on battery and store the log data in memory so that no cable is interfering as the drill pipe is tripped out of the well while the tools are acquiring data. The quality of wireline electrical borehole images in wells drilled with oil-based mud has significantly improved in recent years. Modern microresistivity imagers operate in the megahertz-frequency range, radiating the electromagnetic signal through the non-conductive mud column. A composite processing scheme produces high-resolution impedivity images. The new, ultra-slim borehole-imager tool uses these measurement principles and processing methods. Innovating beyond the existing tool designs the tool is now re-engineered to dimensions sufficiently slim to fit through drill pipes and to use through-the-bit logging techniques. The new, ultra-slim tool geometry proves highly reliable and, due to the deployment technique, highly effective in challenging hole conditions. The tool did not suffer any damage and showed only minute wear over more than twenty field test wells. The tool’s twelve-pad geometry provides 75% coverage in a six-inch diameter borehole and its image quality compares very well with existing larger tools. The field test of this borehole imaging tool covers all scenarios from vertical to deviated and to long-reach, horizontal wells. Geological structures, sedimentary heterogeneities, faults and fractures are imaged with detail matching benchmark wireline images. The interpretation answers allow operators of unconventional reservoirs to employ intelligent stimulation strategies based on geological reality and effective well development. A new high-frequency borehole imager for wells drilled with oil-based mud is introduced. Deployed through the drill pipe and its portal bit, the imager carries photorealistic microresistivity images into wells where conventional wireline conveyance techniques reach their limits in both practicality and viability.
Wu, Junchen (School of Geosciences China University of Petroleum (East China)) | Fan, Yiren (School of Geosciences China University of Petroleum (East China)) | Deng, Shaogui (School of Geosciences China University of Petroleum (East China)) | Huang, Ruokun (Research Institute of Petroleum Exploration and Development, PetroChina Tarim Oilfield Company) | Wu, Fei (Suzhou Niumag Analytical Instrument Corporation) | Wang, Zhongtao (China Petroleum Logging Co. Ltd.)
Abstract Mud filtrate invasion is a complex and time-dependent process. During the process, a zone of finite size around the wellbore (invasion zone) in which a portion of the initial pore fluids have been displaced by the mud filtrate is gradually generated. As a result, the petrophysical and fluid properties of the formation in this zone will be inevitably altered, and sometimes tend to be quite different from their initial values. Petrophysicists and logging analysts have long considered mud filtrate invasion as a nuisance due to its troublesome effect on formation properties and logging measurements, especially on resistivity logging measurements. Note that even deep reading resistivity logging may not see deep enough (beyond the invasion zone), and need to be corrected. Therefore, simulation of mud filtrate invasion under near reservoir conditions is crucial for an in-depth understanding of its physics and effects on logging measurements, and hence for logging interpretation and formation evaluation. Otherwise, this will produce substantial errors in determining initial formation properties, and estimating hydrocarbon reserves and well productivity. To date, most researchers have done a number of works on mud filtrate invasion on the basis of physical simulation at core plug scale. However, conducting invasion experiment on core plug has intrinsic limitations. Firstly, the cylindrical shape of core plug determines that the seepage form of mud filtrate within it (horizontal linear flow) is completely different from that (plane radial flow) in the actual downhole environment, thereby causing a poor representation of the filtration law observed in the experiment. Secondly, due to the small size of core plug, it is almost impossible to monitor the radial resistivity variation for reflecting the dimension and geometry of the invasion zone. To overcome the limitations, a large-sized formation module (sectorial block structure, 55.9 cm in radial depth, and 10 cm in thickness) made by sandstone outcrop was introduced in this paper. Compared with core plug, as a novel type of experimental equivalent, the formation module is larger in size, greater in saturation capacity, and much more similar to the in-situ formation. Its structure can ensure the seepage form of mud filtrate within it is exactly the same as that in the actual downhole environment. Its large size is able to provide enough space and radial distance to follow the entire invasion process from beginning to dynamic equilibrium. The dynamic processes of long-term water-based mud filtrate (WBMF) invasions were duplicated realistically in laboratory. During the whole experimental period, the dynamic invasion data (including radial formation resistivity profile and filtration rate) can be uninterruptedly real-time acquired, thereby investigating and comparing the phenomenon of WBMF invasion in the formation modules with different physical properties. Finally, by combining physical and numerical simulation, the invasion characteristics of WBMF in high-permeability and tight sandstone reservoirs under in-situ formation conditions were quantified. The results obtained in this paper provide an experimental basis and theoretical support for enlightening novel simulation methodologies of mud filtrate invasion, revealing invasion mechanisms, and establishing invasion correction model for electric logging, etc.
Abstract Conventional formation evaluation provides fast and accurate estimations of petrophysical properties in conventional formations through conventional well logs and routine core analysis (RCA) data. However, as the complexity of the evaluated formations increases conventional formation evaluation fails to provide accurate estimates of petrophysical properties. This inaccuracy is mainly caused by rapid variation in rock fabric (i.e., spatial distribution of rock components) not properly captured by conventional well logging tools and interpretation methods. Acquisition of high-resolution whole-core computed tomography (CT) scanning images can help to identify rock-fabric-related parameters that can enhance formation evaluation. In a recent publication, we introduced a permeability-based cost function for rock classification, optimization of the number of rock classes, and estimation of permeability. Incorporation of additional petrophysical properties into the proposed cost function can improved the reliability of the detected rock classes and ultimately improve the estimation of class-based petrophysical properties. The objectives of this paper are (a) to introduce a robust optimization method for rock classification and estimation of petrophysical properties, (b), to automatically employ whole-core two-dimensional (2D) CT-scan images and slabbed whole-core photos for enhanced estimates of petrophysical properties, (c) to integrate whole-core CT-scan images and slabbed whole-core photos with well logs and RCA data for automatic rock classification, (d) to derive class-based rock physics models for improved estimates of petrophysical properties. First, we conducted formation evaluation using well logs and RCA data for estimation of petrophysical properties. Then, we derived quantitative features from 2D CT-scan images and slabbed whole-core photos. We employed image-based features, RCA data and CT-scan-based bulk density for optimization of the number rock classes. Optimization of rock classes was accomplished using a physics-based cost function (i.e., a function of petrophysical properties of the rock) that compares class-based estimates of petrophysical properties (e.g., permeability and porosity) with core-measured properties for increasing number of image-based rock classes. The cost function is computed until convergence is achieved. Finally, we used class-based rock physics models for improved estimates of porosity and permeability. We demonstrated the reliability of the proposed method using whole-core CT-scan images and core photos from two siliciclastic depth intervals with measurable variation in rock fabric. We used well logs, RCA data, and CT-scan-based bulk-density. The advantages of using whole-core CT-scan data are two-fold. First, it provides high-resolution quantitative features that capture rapid spatial variation in rock fabric allowing accurate rock classification. Second, the use of CT-scan-based bulk density improved the accuracy of class-based porosity-bulk density models. The optimum number of rock classes was consistent for all the evaluated cost functions. Class-based rock physics models improved the estimates of porosity and permeability values. A unique contribution of the introduced workflow when compared to previously documented image-based rock classification workflows is that it simultaneously improves estimates of both porosity and permeability, and it can capture rock class that might not be identifiable using conventional rock classification techniques.
Abstract Faulting is one type of structural trap for hydrocarbon reservoirs. With more and more fields moving toward the brownfield or mature operations stage of life, the opportunity to target bypassed or attic oil in the vicinity of bounding fault(s) is becoming more and more attractive to operators. However, without an effective logging-while-drilling (LWD) tool to locate and map a fault parallel to the well trajectory, it has been challenging and potentially high risk to optimally place a well to drain oil reserves near the fault. Operators often plan these horizontal wells at a significant distance away from the mapped fault position to avoid impacts to the well construction and production of the well. Often, the interpreted fault position, based on seismic data, can have significant lateral uncertainty, and uncertainties attached to standard well survey measurements make it challenging to place the well near the fault. This often results in the wells being placed much farther from the fault than expected, which is not optimal for maximizing recovery. In other cases, due to uncertainty in the location of the fault, the wells would accidentally penetrate the side faults and cause drilling and other issues. Conventional remote boundary detection LWD tools do not assist with locating the fault position, as they only detect formation boundaries above or below the trajectory and not to the side. In this paper, the authors propose a novel approach for mapping features like a fault parallel to the well trajectory, which was previously impossible to map accurately. This new approach utilizes a new class of deep directional resistivity measurements acquired by a reservoir mapping-while-drilling tool. The deep directional resistivity measurements are input to a newly devised inversion algorithm, resulting in high-resolution reservoir mapping on the transverse plane, which is perpendicular to the well path. These new measurements have a strong sensitivity to resistivity in contrast to the sides of the wellbore, making them suitable for side fault detection. The new inversion in the transverse plane is not limited to detecting a side fault; it can also map any feature on the transverse plane to the well path, which further broadens the application of this technology. Using the deep directional resistivity data acquired from a horizontal ultra-ERD well recently drilled in the Wandoo Field offshore Western Australia, the authors tested this approach against the well results and existing control wells. Excellent mapping of the main side fault up to 30 m to the side of the well was achieved with the new approach. Furthermore, the inversion reveals other interesting features like lateral formation thickness variations and the casing of a nearby well. In addition, the methodology of utilizing this new approach for guiding geosteering parallel to side fault in real time is elaborated, and the future applications are discussed.
Orban, Nicolas (TOTAL) | Garg, Shashank (TOTAL) | Shaldaev, Mikhail (TOTAL) | Shrivastava, Chandramani (Schlumberger) | Cuadros, Guillermo (Schlumberger) | Marquinez, Victor (Schlumberger) | A, Adrian (Schlumberger) | Wibowo, Vera (Schlumberger) | Domingos, Ricardo (Schlumberger)
Abstract The pre-salt carbonates of Brazil pose drilling and characterization challenges associated with inherent reservoir heterogeneity; and borehole imaging while drilling often provides insights helpful for both, operational and subsequent decisions. The findings and learnings from a 3-well campaign, offshore Brazil are presented to assess and validate a recently deployed high-definition borehole imaging technology that provides industry’s first real-time ultrasonic amplitude images and time-to-depth corrections for best possible images maintaining the geological features integrity. High-definition ultrasonic measurements were acquired at two central frequencies with 0.2-in resolution and provided amplitude and transit time images for geological characterization and petrophysical evaluation in addition to azimuthal ultrasonic calipers. The lossy nature of amplitude data makes it difficult to transmit in real-time; therefore, a unique data compression technology was used to achieve industry’s first high quality amplitude images streaming while drilling. In deepwater operations acquisition of high-definition logging while drilling (LWD) images can be severely degraded if time-to-depth offset due to heave is not compensated. Recently developed heave-filtering workflows ensured the integrity of subsurface features. The time-indexed data was processed with this application in real-time, providing good results and confidence in the capability of this technology. Image-logs of the first well were helpful in interpretation and added value to the reservoir understanding; however, many intervals suffered from lack of confidence in image features. Simulations were performed to improve the images acquisition parameters based on learnings from this experience. New optimized operational parameters were applied in next two wells, resulting in image logs of excellent quality. Data from second well suffered from high heave while drilling, which required implementation of the heave-filtering memory data workflow. For the third well, an additional requirement for real-time image quality-control was defined, requiring data to be processed after every drill-stand. Real-time data quality provided confidence in optimal quality of memory data, thereby eliminating the need of post-drilling wireline operations in open-hole. The images acquired in memory helped characterize intervals of stromatolites with various morphology, and zones of vugs distribution, providing excellent alternative for wireline logging, de-risking the operations in pre-salt carbonate logging in Brazil offshore operations.