High Resolution ChemoSteering in Drilling Horizontal Wells, Kuwait

A maximum reservoir contact (MRC) well, by definition, is a single or a multilateral horizontal well with more than five km of total contact with the reservoir rock. Planning of these wells requires extensive modeling studies to optimize total length, placement and configuration of branches. The main objective behind the MRC well concept was to improve individual well productivity and hence reduce the unit development cost and to better develop hydrocarbon assets. In fact, oil fields developed using MRC wells shows significant improvements in those wells performance in terms of increased PI, lower drawdown, and significantly delaying water and gas conning. A major challenge that faces production engineers in their daily operations is identifying and accessing laterals windows in those MRC multilateral wells, in order to preform rigless downhole sensing and intervention jobs (logging, stimulation, etc.). This challenge varies in difficulty based on the technology advancement of multilaterals (TAML) level, for example in TAML level 2 wells (cased mainbore) metal logging tools such as casing collar locator can be used to identify and confirm the access of laterals, while this of course is not an option in TAML Level 1 multilateral wells (open hole mainbore and lateral). Another reason selective re-entry of TAML Level 1 is considered very difficult is due to the shape and quality of the wellbore near the junction (window), post drilling and after distortion of hydrocarbon flow. This paper presents an intelligent electromechanical tool, jointly developed to address this issue. The tool consists of a sensing package that can identify and locate the depth and orientation of the lateral window using US and EM sensors, and an electromechanical arm that can be easily rotated and actuated with a wide range of angle, to lead and steer the bottom-hole assembly into the required lateral. This paper also presents the discoveries, challenges, and results of testing this intelligent tool in two TAML Level 1 multilateral oil producers, one fishbone well with a mainbore and six open hole laterals branching from it (shut in conditions) (Mohannad Abdelaziz, 2016), and the other is an open hole well mainbore with a lateral branching from it (shut in, flowing conditions). In Both trials the tool was successfully used to guide a production logging tool into different wells laterals.

Placing a maximum reservoir contact well in a thinly layered reservoir has always been a challenge. Experiences showed that the well trajectory could easily be steered out of the target, necessitating expensive plug-back and redrilling operations to ensure that the well is drilled as planned. With the deployment of advanced LWD technologies, such as density image (DI), resistivity image (RI) and directional deep resistivity (DDR) logging tools, and high speed real time satellite data transmission, well paths can be geosteered from anywhere and kept in a thinly layered reservoir. The first Saudi Aramco field examples of utilizing RI and DDR are shown to demonstrate the added values of new technologies in geosteering difficult-to-drill wells. In some of the examples, images of density and resistivity are consistent and all could be used for geosteering. In other examples, wrong geosteering decisions would have been made had the DI been the only available tool. With the help of RI, reservoir contact of multi-lateral wells is increased. Examples also show that using DDR can prevent the well trajectory from being too close to the zero porosity rock layer or the underlying water. Introduction The main oil producing reservoir in the XA field is a massive carbonate reservoir. At the top of this good quality reservoir, there is a thin heterogeneous reservoir interval (named L1Z1) with rock porosity ranging from less than 10 porosity unit (pu) to more than 20 pu (Fig. 1). This L1Z1 is sandwiched between an 8' thick overlaying zero porosity anhydrite unit and an underlying 2' thick zero porosity anhydrite or close to zero porosity anhydritic dolomite unit. The thickness of L1Z1 ranges from less than a few feet to more than 20', with a typical thickness from 4' to 8'. Because of the rock quality, this thin layer has been difficult to target through traditional vertical producers. To improve oil recovery, maximum reservoir contact (MRC) multi-lateral (ML) horizontal wells have been drilled in the last few years; some drilled in new locations and others sidetracked from existing vertical wells. Conventional Geosteering Tools It is impossible to place a horizontal well in a thinly layered reservoir such as L1Z1 without the help of logging-while-drilling (LWD). Traditionally, LWD tools consist of gamma ray (GR), density, neutron, and resistivity (triple combo) measurements. Geosteering a horizontal well with only conventional LWD triple combo and GR are difficult because they do not provide direction of the measurement.

Optimizing production from a multilateral well requires understanding and characterization of the well and completion performance in the flow path from the reservoir to the separator. Situations when crucial information may be gathered includes transient flow phases such as cleanup and restart after shut-ins. Understanding the inflow from the near-wellbore into each lateral and monitoring the functionality of completion components are important tools in establishing completion effectivness and wellbore performance. This paper describes new applications of chemical tracers in multilateral horizontal wells and utilizes flowbacks in understanding cleanup efficiency, confirming inflow from the toe-section of long horizontal wells and monitoring the functionality of ICV components based on a case study on four multilateral wells in the Alvheim field, Norway. A new generation of chemical tracers were embedded in a polymer matrix and installed in ICD screens on four long horizontal multilateral wells. In total, 27 unique oil tracers were used for 12 months of oil marking period designed for monitoring early production. The oil tracers were released when the tracers were in contact with oil and mobilized to topside sampling point with the produced fluids when the wells were opened for cleanup. The samples were analyzed in a laboratory and the tracer responses were used to study cleanup efficiency and to monitor ICV during sequential cleanup of laterals. The tracers were also used to understand the inflow contribution from the toe section of each lateral. The case study showed that intelligent well tracers provide a direct proof of contribution from the toe-sections of the multilateral wells and enabled monitoring of ICV functionality and synchronization.

The article discusses the issue of drilling multilateral horizontal wells and provides a brief history of its development. Data were provided on the selection of the location of the multilateral horizontal well, drilling the main wellbore and determining the depth for running the сasing strings. This paper also analyzes the selection of lateral wellbore penetration depth, the importance of drilling multilateral horizontal wells and their application for the first time in the shelf water of South Caspian Basin, at the Western Absheron field, Well 19. Keywords: multilateral wells; drilling of horizontal wells; petrophysical models; drilling of main and lateral wellbores.

This paper presents a methodology for more accurate reservoir characterization with a field example of Maximum Reservoir Contact (MRC) well evaluation using dynamic production logging and near wellbore simulation modeling. Ultimately, once the results of these analyses are input into geological models and field simulators, more accurate answers would be obtained. The study was initiated to honor advance production logging results in inverse manner and to explain crossflow behavior. MRC well consisted of two lateral and motherbore and production logging results provided contributions of each lateral (3 rates) and crossflow during shut-in (total of 4 rates during survey) and during small choke. These measurements and results suggested that the choke size should be optimized for better production and drainage strategy. Comprehensive data integration was performed for more accurate modeling, including all production and injection histories of offset wells and drilling history. Fine unstructured grid refinement was utilized for near wellbore modeling. The multilateral well has been numerically modeled including friction to match production logging results and to obtain horizontal and vertical permeabilities between layers. Crossflow was also reconstructed in a quantitative manner. To the best of our knowledge, this is the first study with actual data honoring flow contributions and capturing such observations. Sensitivities were also carried out for injection and production history on crossflow behavior.

Techbits Horizontal and multilateral wells took center stage at an SPE Applied Technology Workshop (ATW) held earlier this year in Penang, Malaysia. The workshop, titled "Maximizing the Value of Horizontal and Multilateral Wells: New Challenges, Technologies, and Approaches," gathered 70 participants from around the world for discussions aimed at addressing new applications of multilateral and horizontal well technologies. The ATW included sessions reviewing lessons learned in drilling horizontal and multilateral wells, as well as the new technology offerings that promise to maximize oil and gas production from them. The specific range of topics included field-development planning, reservoir evaluation, the use of intelligent technology for efficiency gains, drilling and completion issues, and stimulation. The ATW's opening session provided an overview of the development history of horizontal and multilateral wells within Saudi Aramco. Current well practices are built upon learnings from past experiences in the areas of reservoir characterization, well placement, well-structure optimization, and intelligent completions to yield maximum production benefit. The opening session also encouraged attendees to focus on tackling the challenges of applying this technology in today's energy and economic environment. Technology Overview The industry organization Technical Advancement of Multilaterals (TAML) opened the technology overview session with a review of its programs designed to promote global development and utilization of multilateral technology within the industry through open dialog and information exchange. Apache Corporation next provided an operator's perspective of development strategies in planning horizontal and multilateral wells. Emphasis was placed on ways to maximize hydrocarbon recovery while also keeping costs to a minimum. Investment and asset development were analyzed through the entire asset lifecycle, from discovery to decommissioning. An operator considering a horizontal or multilateral completion solution must carefully evaluate the suitability of the design concept for each asset, from both a cost-effectiveness and safety/risk point of view. Drilling and Completion While discussing specific drilling- and completion-related issues, attendees agreed that a thorough understanding of how a particular drilling or completion design scheme may impact other disciplines is vital. For example, during the development plan for a multilateral well it is important to consider the geology and condition of the reservoir, as well as future plans for production, stimulation, and intervention. Field examples from both an operator (OMV New Zealand) and a service provider (Baker Oil Tools) illustrated the importance of having a multidisciplinary team work together to consider the various factors in their drilling and completion design, which are not limited to:Debris managementDepth control and orientationContingency plans and risk assessmentIntervention and plug/abandonmentSend control screen, openhole gravel pack or cased-hole fracture pack

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112616, "Troll West Oilfield Development-How a Giant Gas Field Became the Largest Oil Field in the NCS Through Innovative Field and Technology Development," by Richard Dyve Jones, StatoilHydro, and Erland Saeverhagen, SPE, Arve K. Thorsen, SPE, and Sveinung Gard, SPE, Inteq, prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed. The Troll West oil field has been developed with more than 110 horizontal subsea wells including 53 multilateral (ML) wells. The thin oil rim was developed through extensive use of multilateral drilling and wells containing up to 7 horizontal branches. The process of drilling the ML wells and the benefit/risk evaluation for the ML process are discussed. Introduction The Troll field is offshore Norway on the Norwegian Continental Shelf (NCS) in 300-m water depth, as shown in Fig. 1. The field was discovered in 1979 and covers an area of 750 km2. Drilling of the production wells began in 1994, and production began September 1995. Oil production to September 2007 was 188.3×106 m3 of oil, all from horizontal wells. The 250 horizontal sections have drilled 900 000 m, including 560 000 m of reservoir section. Field Description and Challenges Gas and oil are found mainly in the Sognefjord formation and in the underlying Fensfjord formation. The oil in the Troll West is from a 22- to 26-m thick oil column under a small gas cap. In the Troll West gas province, there is a 12- to 14-m-thick oil column and a gas column up to 200 m thick. The Troll reservoir sands are of two distinct types, with large grading between. The C sand is a clean coarse sandstone, with permeability ranging from 1 to more than 10 darcies. The M sand is micaceous, with a finer grain size than the C sand, and, in general, has permeabilities in the range of 1 to 100 md. The sorting in this sand is poorer than in the C sand; therefore, the permeability is less. Recovery Strategy. Oil production is through long horizontal wells drilled just above the oil/water contact (OWC) in the thin oil zone. The main recovery strategy is pressure depletion, but with simultaneous expansion of the gas cap above and the water zone below the oil. In the Troll West oil province, some of the gas produced has been injected back into the reservoir to optimize the oil production. One important aspect is to recover the oil quickly, because less oil can be extracted when the pressure declines in Troll East. Therefore, limits were placed on gas extraction from Troll East.

Due to high energy density, clean combustion products and abundant resources, natural gas hydrates (NGHs) have been regarded as an important clean energy source with the potential for large-scale development and utilization. However, pilot tests in NGHs show that their production rates are far below commercial needs. Multilateral well technology may lead to a solution to this problem because it can dramatically expand the drainage area of production wells. This paper presents the practical rate transient analysis for multilateral horizontal wells in NGHs. In developing solution to the diffusivity equation of multilateral horizontal wells in NGHs, the superposition principle and reciprocity are applied. We wrote the governing equation in cylindrical coordinates to describe the NGH flow process. We used the moving boundaries and dissociation coefficients to model the solid-to-gas transition process in hydrates. To obtain solutions for flow in hydrate reservoirs, we used Laplace transforms and the Stehfest numerical inversion method. Superposition principle and Gaussian elimination are applied to obtain the desired solution for multilateral horizontal wells. We validated our proposed model with a commercial numerical simulator. By performing sensitivity analyses, effects on production behavior of the number of branches, dissociation coefficient, radius of the region with dissociated hydrate, and dispersion ratio are determined. A synthetic case study is conducted to show the typical production behaviors.

This paper presents a case history of the use of remotely operated hydraulic Interval Control Valves (ICVs) as a simple and cost effective method of controlling multiple laterals for selective water shutoff. Post installation production testing and impact on production are described. The Saih Rawl Shuaiba reservoir in central Oman is a low permeability limestone reservoir producing light oil with pressure maintenance by means of a waterflood. Extensive development started in the early 1990's when multi-lateral horizontal well technology enabled economic production rates from wells and sustainable water injection for the waterflood. Multi-lateral wells of 4 to 7 legs are typically drilled for both producers and injectors with producer to injector leg spacing gradually decreasing from 250 m in the initial development to 60 m at present. As a consequence of this development philosophy, production has been accelerated, but control of sweep and water breakthrough has become a problem. A hydraulic multi-drop intelligent well completion has been successfully installed and operated in a Saih Rawl Shuaiba well that allows each of the 4 laterals legs to be independently opened and closed at will from surface using three hydraulic lines. The concept is purely a hydraulic control system that allows for multiple downhole devices to be controlled with the minimum number of control lines. This is achieved using hydraulic pressure sequencing and a mechanical decoder downhole along with a hydraulically operated control valve to give simple on/off zonal control. Retrievable hydraulic line feed-through packers are used to isolate one lateral from another. This intelligent well system has been integrated with the ESP installation with the provision of a hydraulic disconnect, allowing the replacement of the ESP (upper completion section) without affecting the lower intelligent well section. Control line hydraulic continuity is re-established upon ESP replacement. Introduction The Saih Rawl Shuaiba is a low permeability limestone reservoir producing light oil. Saih Rawl wells generally require artificial lift in conjunction with water injection to optimize oil recovery from the matrix carbonate reservoirs of the Shuaiba formation. The development concept used encompasses multilateral horizontal producers paired with water injectors for pressure maintenance and sweep.1, 2, 3 Although the reservoir properties appear relatively homogeneous, digenetic processes like karstification and natural fracturing created considerable heterogeneity. The resulting digenetic areas with relatively high porosity and permeability may cause direct communication between injector and producer, making quantification of a producers potential extremely difficult. Development started in the early 1990's when multilateral horizontal well technology enabled economic production rates from wells sustained by water injection. Multilateral wells of 4 to 7 legs were typically drilled for both producers and injectors with producer to injector leg spacing gradually decreasing from 250 metres in he initial development to 60 metres at present, in order to improve sweep efficiency and ultimate recovery.

Enhancing hydrocarbon production and optimizing recovery at the lowest possible cost are the objectives of an oil field development research. Coning issues, gas smeared, and oil lost into the gas cap are always linked to optimizing oil production from oil rim reservoirs with an underlying aquifer and an overlaying gas cap. These issues will lower the oil recovery factor. Oil rim reserves are viewed as marginal by the majority of oil firms. A model with a horizontal and multilateral well in an oil rim reservoir is simulated using the Schlumberger Eclipse 100 Black oil simulator, with the horizontal well serving as the base-case. Sensitivity analysis, cost evaluation of the advantages of the multilateral well over the horizontal well, and the impact of standoff from such reservoirs were also investigated. The analysis of the simulation results, cost analysis, and sensitivity analysis revealed that the horizontal well produced 132,287 STB, a higher field oil production rate, and a good amount of profit than the multilateral well, which presented an increased oil production total of 134,135 STB. With 132,287 STB, the horizontal well's standoff resulted in the highest oil recovery production because to its tiny size. However, when the standoff was severe and the laterals were widely spaced, more oil—134,135 STB—was collected from the multilateral well. According to the aforementioned findings, multilateral wells can be utilized in an oil rim reservoir to improve oil recovery as opposed to traditional techniques, which do not yield the best output and render the oil rim reservoir marginal.

High water production is a major issue in horizontal oil wells, especially in longer laterals, because of the high drawdown from the heel to toe. In addition, the presence of heterogeneity along the lateral section can lead to uneven sweep of hydrocarbons which can result in poor recovery. To control the water production and achieve better sweep efficiency, ICDs have been introduced which balance fluid flux along the producing horizontal well. This paper discusses the feasibility and results of using integrated technologies such as ICDs along with rotary steerable drilling systems (RSS) and azimuthal logging while drilling well placement technology to achieve higher reservoir sweep efficiency. This case study is focused on a Gulf of Mexico (GoM) shelf horizontal well which was completed with prepacked screens. The well was sanded in and plugged after five years of high water production. A saturation log was run in the offset well which granted the viability to revisit this reservoir. Consequently, a new offset horizontal well was proposed and drilled next to the existing well to sweep out remaining reserves. For the new offset well, full field dynamic simulations were performed to evaluate attic placement methodology and optimization of Inflow Control Devices (ICDs) into the integrated design. The results illustrate that attic horizontal well placement is feasible using integrated drilling with ICD technology to maximize the sweep efficiency.

Multilateral wells are mentioned as technologies to improve reservoir recovery rates. Some strategies are simple and straightforward, while others are far more complex. Such complex completions enable the use of multilateral wells in a much broader range of well-scenarios, but they also create a new set of obstacles, concerns, and threats. Few operators, however, were prepared to design a multilateral well. The Fishbone wells are new production techniques that have been introduced to improve productivity and provide access to complex geological types and reservoirs. The main benefit is the low cost and short time required to run this system. This study discusses a project that demonstrate the concept of using multilateral wells as an alternative by comparing it to two conventional horizontal wells, which can lead to a significantly lower operating cost. The primary goals of this work are mainly to design a multilateral well scenario with five wellbores (Wellbores #1, Wellbores #2, Wellbores #3, Wellbores #4, and Wellbores #5) to increase oil production from offshore oil fields and evaluate their productivity and economics. The Landmark Software, COMPASS is utilized to design the plan trajectories, CasingSeat is used to determine the best casing design and suitable casing ODs, and the tNavigator Software is used to assess oil recovery and economy. The most production was found in multilateral wells formed by Fishbone. When compared to conventional horizontal wells, these multilateral wells provided more oil over a longer period of time with lower operating costs. As a result, the net profit has been calculated, and the multilateral well performed better because its total net income exceeds that of the two horizontal wells to be drilled.

The changing economics of oilfield development has resulted in operators, and therefore, service companies, being challenged to produce greater quantities of oil at reduced costs. Deeper and more corrosive environments are being produced to increase production capacities, and new technology is being encouraged in the attempt to generate as much "value" from a well as possible. This pursuit and the resulting development of new techniques have been major factors in allowing not only projects that traditionally would not have been viewed as economically feasible to be attempted but also the lives of existing fields in which production has been declining to be extended. This paper will discuss the specific techniques used to drill and complete several multilateral horizontal wellbores in the Middle East. The discussion will focus on how the latest developments in drilling technology were employed to successfully drill the horizontal wellbores in the subject wells. Additionally, the completion systems used to permit control and access of the multiple wellbores in these wells will be presented. The paper will also review other developments in drilling technology that can facilitate success in applying this technology. This paper draws upon specific field case histories in the Middle East to demonstrate the techniques discussed and their economic benefits. Introduction The multilateral concept is a prime example of innovative technology that has been used to support current economic needs, and operators in the Middle-East have been among the pacesetters in the use of this new concept. In this type of completion, a unique system mechanically connects horizontal laterals to a parent wellbore and allows production from the individual laterals to be commingled or selective. In 1996, it was estimated that over 35 multilaterals of various descriptions were drilled in the Middle-East. Actually, the multilateral well concept is not new, with the first recorded multilateral dating back to 1953 to a field in Russia, but it has only been since the early 1990's that the conceptual techniques have progressed sufficiently for it to be considered as fully developed. The values of the multilateral concept have always been recognized, but traditionally, the drawback to its use has been the completion techniques available and their capability to allow remedial work to be conducted. To date, approximately 85% of multilaterals have been openhole sidetracks with no liners or completion equipment, but as can be seen in the recent revisiting of this concept, these limitations have been overcome for the most part. In looking at the financial drivers of a multilateral well, the unproductive (or vertical) part of the well is considered as "cost-driven," while the productive part of the well (the deviated or horizontal sections) would be considered as "value-driven." By definition, therefore, a multilateral well, especially if it is a re-entry, can be considered almost entirely as a "value-driven" process. Thus, the technology and processes that are available must be carefully evaluated to ensure that a multilateral is the correct option for the scenario under evaluation. As with all new and developing technologies, it must also be recognized that in addition to the advantages to be gained, there may be additional technical and economic risks that should be carefully evaluated. Multilateral technology can be used in a variety of scenarios such as infill field development where available slots are limited, field life extension by accessing newly defined reserves, or deepwater developments. Generally, multilaterals can be broadly divided into two categories:Re-entries - where an existing well is re-entered, and multiple branches drilled off the existing wellbore.New developments - where a new well is drilled with the intention of completing as a multilateral of some type. P. 31

Multilateral completions provide unique systems that mechanically connect horizontal laterals to parent wellbores and allow selective or commingled production from the individual laterals. This paper will discuss the specific techniques used to drill and complete several multilateral horizontal wellbores in the Middle East. The discussion will focus on how the latest developments in drilling technology were employed to successfully drill the horizontal wellbores in the subject wells. Additionally, the completion systems used to permit control and access of the multiple wellbores in these wells will be presented. The paper will also review other developments in drilling technology that can facilitate success in applying this technology. This paper draws upon specific field case histories in the Middle East to demonstrate the techniques discussed and their economic benefits. Introduction The changing economics of oilfield development has resulted in operators, and therefore, service companies, being challenged to produce greater quantities of oil at reduced costs. Deeper and more corrosive environments are being produced to increase production capacities, and new technology is being encouraged in the attempt to generate as much "value" from a well as possible. This pursuit and the resulting development of new techniques has been a major factor in allowing projects to be attempted that traditionally would not have been viewed as economically feasible. The multilateral concept is a prime example of innovative technology that has been used to support current economic needs, and operators in the Middle-East have been among the pacesetters in the use of this concept. In 1996, it is estimated that over 35 multilaterals of various descriptions were drilled in the Middle-East. Actually, the multilateral well concept is not new, with the first recorded multilateral dating back to 1953 to a field in Russia, The value of the concept has always been recognized, but traditionally, the drawback to its use has been the completion techniques available and their capability to allow remedial work to be conducted. As we shall see, however, in the recent revisiting of this concept, these limitations have for the most part been overcome. In looking at the financial drivers of a multilateral well the unproductive (or vertical) part of the well is considered as "cost-driven," while the productive part of the well (the deviated or horizontal sections) would be considered as "value-driven." (Fig. 1) By definition. therefore, a multi-lateral well, especially if it is a re-entry, can be considered almost entirely as a "value-driven" process. Thus, the technology and processes that are available must be carefully evaluated to ensure that the maximum value will be generated from the horizontal laterals. Multilaterals can be broadly divided into two categories:Re-entries - where an existing well is re-entered, and multiple branches drilled off the existing wellbore.New developments - where a new well is drilled with the intention of completing as a multilateral of some type. Multilateral technology can now be used as a developmental concept for an entire field and can result in significant savings. For example, as can be seen in Fig. 2, a field that would normally be drilled with single deviated or even horizontal wells would require much larger platform facilities and require considerably more footage to be drilled when compared to a field developed with multilateral wellbores. Planning and Development of Design Concepts In planning a multilateral project. it is important that a multidisciplinary developmental team be employed for the initial planning stages. The team should include drilling engineers, reservoir engineers, geologists, and petrophysicists from the operator as well as multilateral (MLT) and completion specialists, directional drillers, and logging-while-drilling (LWD) specialists from the service company. P. 115^

The CD carbonate of the Ngimbang formation in the X-Field, East Java Basin, has multiple reservoir targets with varying flow units due to secondary porosity from karst processes. Each of these reservoirs are thin, and the continuity of the karst within the reservoir is quite random. The amount of producible hydrocarbon will depend on the length of the drain section along the reservoir and the amount of karst intersected by the wellbore trajectory. Thus, maintaining the trajectory inside the carbonate reservoir while mapping and targeting the karst position is especially important for hydrocarbon productivity. Many horizontal and high-angle wells were drilled from the first offshore platform in this field as part of the phase one development plan. To maintain production in the field, a new offshore platform was placed south of the first platform, targeting new development areas in the field. Five horizontal wells were planned as part of the second development phase. The first horizontal well to be drilled in the second phase was the most challenging well because of the high uncertainty in the structural dips along the lateral length caused by the low-seismic resolution data and the limited number of nearby offset wells for control points. Moreover, the offset wells had inconsistent log properties, which complicates for correlating the well landing in the targeted karst level within the reservoir. Initially, a pilot hole was planned to reduce the landing uncertainties; however, drilling the pilot hole was being challenged for cost efficiency. As a result, a geosteering strategy was proposed instead, comprised of landing and geosteering using a new logging-while-drilling (LWD) combination of a new high-definition reservoir mapping technology, high-resolution laterolog borehole imaging technology, and multifunction LWD tool. This paper presents the complete preparation procedure of the geosteering project, strategy, and evaluation using this new LWD combination for improved reservoir interpretation. The deeper reading and higher resolution of the new reservoir mapping technology enabled continuous mapping of the target reservoir boundaries that reduced the structural uncertainties in the seismic measurements, and for the first time, revealed the karst architecture within the reservoir with greater details. This high-definition information helped to land the well precisely in the target karst sweet spot, improved the understanding of the karst characters along the trajectory, and provided greater confidence in the real-time geosteering decision. The high-resolution borehole image revealed the carbonate rock texture and karst and vugs appearance on a smaller scale, which was used to analyze the secondary porosity distribution and contribution along the wellbore trajectory. Integrating this additional information while drilling allowed for bridging the gap from seismic to reservoir scale, and finally linking the information to the high-resolution borehole image for improved geological understanding; therefore, improved geosteering strategy in the field.