Drilling long laterals within Shuaiba limestone reservoir without exit to Nahr-Umar shale in the challenging field "B" that is characterized by geological uncertainty can have major risks. The low to very low resistivity environment reservoirs are common in Oman especially while placing wells nearby OWC; on a reservoir spot window of 1-2m TVD only. The main objective is to place the well less than 1m TVD below the reservoir top, this was achieved by utilizing Multilayer Bed Boundary Detection and Rotary Steerable System. Integrating propagation resistivity curves response with the directional resistivity curves response from Bed Boundary detection tool have been used as a guide for an optimal well placement in low resistivity reservoir, along with Rotary Steerable System are one of the best strategies which have been used to place the wells within the right spot. For tight geosteering window with an aggressive formation tendency pushing the azimuth left or right and continues inclination instability associated with the existence of an interbedded layers of hard streaks within the reservoir, a faster and more competent Rotary Steerable System tool and Bit selection is required, as proven it provides better stability results for achieving well placement objectives and respond in fast manner to geosteer in real time. The objective of this paper is to describe the geosteering logging while drilling (LWD) technology and technique and Rotary Steerable system (RSS).

The objective is to increase the production/injection rate of the existing old sick vertical wells that are completed with 7" casing, by extending the reservoir exposure with converting those wells to horizontal producer/injector. In the initial Field Development stage, many wells were drilled and completed with 7" casing up to the surface. Several of those old wells are lying inactive in North Kuwait which has one of the largest oil reservoirs in the country. In addition, of the limited surface locations in the field combined with the growing anti-collision challenges, feasibility studies were carried out for reviving such sick wells which can't be delivered via limited hole sections; accordingly, an innovative idea introduced to complete those wells with 3 7/8" or 4 1/8" Open Hole Completion. To address the required challenges, 2-7/8" PAC HT DP had been used along with 3 1/8" Motor. Consequently, DP had to be spaced out every trip to maximize the WOB transfer and mitigate Buckling issues. This paper provides an overview of 3 7/8" slim horizontal hole by taking the challenge to the next level by drilling the longest 3 7/8" horizontal slim hole in the world with a total footage of 4,565 ft. Total 7-runs had been performed to achieve this lateral length due to the limitation of BHA/LWD Battery life. Thirteen such wells have already been drilled consisting of 7 Injectors and 6 Producers. The Slim Wells are completed as an Injector with 5" seal assembly along with 4 ½" Tubing, or as a Producer with 3 ½" tubing and ESP. All wells (both Injectors and Producers) have yielded results commensurate to the potential of any new conventional horizontal well. Consequently, Slim Hole Horizontal wells were successfully drilled in Kuwait Oil Company fields. As such, the campaign of reviving the sick wells helped KOC to achieve higher return on investment in mature assets through minimizing top hole construction cost and time. The success has opened up new avenues for KOC. Re-entry wells helped to achieve higher return on investment in mature assets through minimizing top hole construction cost and have been drilled at 1/3rd the cost of a new well. It also accelerates time to oil production from existing wells and has minimized the prevailing location constraints. KOC has launched an aggressive plan to complete more such sick wells.

A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and to avoid colliding with other offset wells. The selection of the wellbore survey tools within the survey program are limited to the current accuracy available to the industry. A newly developed wellbore survey technique has proven to have superior accuracy compared to the current standard measurement-while-drilling (MWD) surveys with in-field referencing and multi-station analysis (MSA). In almost every drilling bottom hole assembly (BHA), there is an MWD survey tool to survey the wellbore while drilling. Accuracy of the MWD surveys has been improved over the years by correcting potential error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, limited global geomagnetic reference, and gravity model accuracy. This new positioning technique takes the accuracy of MWD surveys to the next level by combining surveys from two independent survey packages. The second survey package is installed inside the rotary steerable system (RSS). Surveys from both packages are retrieved while drilling. Results have been obtained from multiple runs worldwide, enabling comparisons between the new technique and standard MWD surveys from both an enhanced accuracy and true wellbore placement point of view. A proposed error model is based on both the theoretical improvements in accuracy and the empirical proof from the data analyzed. The improved accuracy while drilling assures higher confidence that the well placement will maximize reservoir production and avoid collision with nearby offset wells. In reservoir sections, the wellbore survey accuracy limits the lateral spacing, and this constrains the reservoir production. In top and intermediate sections, wellbore survey accuracy limits the well plan, and this affects how close the well can be drilled in proximity to other offset wells. This directly impacts the complexity of the directional work and the cost per drilled foot. The new technique unlocks the potential to significantly improve the wellbore positioning accuracy.

In the oil and gas drilling process, measurement-while-drilling (MWD) systems are usually used to provide real-time monitoring for the position and orientation of the bottom hole assembly (BHA). The current MWD systems can be categorized into magnetometer-based systems and gyroscope-based systems, which both compute the wellbore trajectory based on stationary surveys at the desired station using a mathematical model with certain assumptions. This current technology neglects the actual trajectory between surveying stations. This research proposed a system using low-cost strapdown inertial navigation system (SINS) to avoid the limits of traditional methods. Demands have been rising for a continuous survey that captures the actual trajectory between the stationary surveying stations, especially in case of directional drilling process. Based on this technology, "dogleg" along the trajectory can be estimated more accurately. Therefore, a low-cost SINS consisting of three MEMS accelerometers and three MEMS gyroscopes is proposed to estimate the trajectory and satisfy the cost demand of commercial companies. This MWD surveying system could eliminate the size constraint of conventional inertial sensors and thus can be used in small well drilling. The core algorithms in the system are SINS mechanization and unscented Kalman filtering (UKF). Due to the large noise in MEMS sensors especially under large shocks and high vibrations, this wellbore survey system will exhibit an unlimited growth of position, inclination, tool face angle and azimuth errors if there are no external observations to update the surveying system. The following external aiding information can be used as updates for the MEMS-based INS in the drilling procedure: the length and velocity information of the total pipelines, the zero velocity information during periodic stop intervals and azimuth information from the magnetometers. Performances the following different solutions: (1) MEMS sensors; (2) MEMS sensors + length/velocity update; (3) MEMS sensors + length/velocity update + ZUPT; and (4) MEMS sensors + length/velocity update + ZUPT + mag-based heading were analyzed. The proposed method was validated by 4 different simulation cases with respect to a typical wellbore trajectory: build, hold and drop wellbore profile. Situations of external aiding information being temporarily unavailable were considered in the simulation. The performance and feasibility of the presented continuous borehole surveying method had been demonstrated in this paper. The proposed low cost SINS-based MWD method can eliminate the costly nonmagnetic drill collars for the magnetometers, overcome the size limitation of gyroscope-based MWD systems for small wells drilling, survey the borehole continuously without interrupting the drilling process, and improve the overall accuracy by utilizing UKF technique.

Challenges of oil recovery in mature assets continue to increase, requiring horizontal wells to be drilled for longer intervals. To improve the overall production in Kuwait, horizontal injector wells are required in some carbonate reservoirs in north Kuwait fields with the main objective of driving reservoir pressure in cases where aquifers cannot contribute to sustained oil recovery. Drilling several injector wells with long lateral sections was found to be the best approach to improve reservoir sweeping efficiency and drive the pressure regime for sustaining higher production levels. Historically, all horizontal wells drilled in similar reservoirs utilized oil-based mud (OBM), which was instrumental in reducing torque and friction along the lateral sections. Recently, all injector wells in the area were switched to water-based mud (WBM) systems in the lateral to reduce reservoir damage and improve injectivity and to enable the use of microimaging logging tools while drilling. This switch, together with limited drilling rig capability and geological uncertainty, posed major challenges on the deliverability of the horizontal section to planned total depth (TD). The operator, in collaboration with the drilling services provider and other service providers, completed a substantial planning phase to optimize the well design and make it achievable using current resources. The bottomhole assembly (BHA) was modeled, with iterations made to enhance the capability of drilling long laterals with proper weight transfer without sacrificing well stability or directional control. To overcome the challenge of drilling the long lateral section without the need for intermediate trips, the tool string design was customized for additional robustness and durability. Completed in two runs, the 6979 ft section was considered to be the longest lateral in north Kuwait ever achieved at the time. Maintaining the well in the desired trajectory, the motorized rotary steerable system was used to achieve a rate of penetration (ROP) improvement above the field average and within the allowable torque limit permitted, reaching the required total depth successfully. The bit and BHA selection and design were both critical to success. The subject reservoir known for high rock stresses and varying local formation dip angles posed a challenge to maintain the well on the desired trajectory due to unpredictable changes in the BHA tendency. Rotary steerable system (RSS) automation through the use of closed loop and cruise control features helped minimize human intervention. These features enable the RSS to automatically react and change downhole settings to track target inclination. This paper discusses the planning, design and execution of the subject well, in addition to the added value and resulting improvement in reservoir sweeping efficiency.

The Mauddud reservoir in the Raudhatain and Sabiriyah fields of north Kuwait includes production layers that were historically exploited using vertical wells. As lower layers begun producing water, horizontal producers from upper layers were planned. A recent simulation study was performed for electrical submersible pumps (ESPs) in the reservoir. ESPs must be placed vertically and as near to the target layer as possible for maximum sweep effect, and as a result, greater build rates in the build section of the well were required to enter the reservoir laterally at the optimal depth. With a requirement for these wells to be drilled with a rotary steerable system, a high build rate (HBR) rotary steerable system (RSS) is required. An upgraded true point-the-bit (PTB) RSS was run for the first time with a polycrystalline diamond compact (PDC) bit in a matched system. A logging-while-drilling (LWD) suite was used while drilling the build section and steer into the target reservoir. The RSS was modified to increase the effective bend angle at the bit and optimize the fulcrum point geometry for high dogleg capability. Bottomhole assembly (BHA) modeling was performed to optimize the stabilization while simultaneously managing stresses in the BHA. Bit designs were optimized with an integrated bit-BHA model to provide sufficient lateral aggressiveness and good hole quality. Extensive planning and BHA optimization exercises were performed to address the challenge. The initial field tests were performed in Kuwait, and the planned trajectory was initially designed with a +/- 10 deg/100 ft build rate. The proposed system was successfully run and exceeded requirements; While drilling the build section, the real-time LWD correlation showed the target formation coming in 19 ft shallower than was initially estimated, requiring a higher than planned dogleg to land the well in the target zone. The RSS deflection was increased to increase the dogleg output, based on the updated target location. The upgraded RSS responded immediately and the system was able to deliver in excess of 12 deg/100 ft build rate, producing a smooth curve at high rate of penetration (ROP) and with low vibration – achieving the target TVD required. A high build rate capability using the PTB system was proven while sustaining the PTB advantages, including superior hole quality, enhanced directional control, and reduced drilling time. This new development provides a unique capability to the industry in a true PTB RSS system with high dogleg capability. Good hole quality and steerability of a PTB RSS can now be achieved simultaneously in high dogleg applications. Good hole quality combined with precision in wellbore control improves drilling performance and completion installation in high dogleg applications. This capability enhances the project economics and enables increased production potential.

Drilling and producing oil wells safely and with minimum risk of environmental hazards is crucial in Abu Dhabi offshore fields. A significant challenge to achieve this goal is steering in very selective sub-layers without conventional radioactive source porosity tools. Acquiring real-time data is critical, especially when drilling slim holes with long horizontal drains, and a well profile that targets several thin reservoir beds. To meet this challenge, a nuclear magnetic resonance (NMR) sourceless porosity tool was introduced for the first time in this reservoir in a six-inch hole. Two lateral drains, each more than 3,000 ft., were drilled, targeting different reservoirs. As a part of the geosteering methodology, nearby offset well properties were incorporated to generate a forward model along the planned well trajectory. The forward integrated geosteering model was updated in real time with porosity and gamma ray data, resistivity images and, structure views, etc. Decisions were made from this input to place the trajectory in the optimum target zones, achieving the reservoir objectives. This paper demonstrates the successful use of an NMR sourceless tool's real-time data acquisition that played a significant part in facilitating effective geosteering and well placement. Real-time NMR total porosity was critical to confirm optimum well placement, especially where lateral facies variations were expected and due to the limited availability data for such a green field. In addition, the available porosity distribution was used to estimate a permeability index. This index, after normalization to offset the well data, was used for selecting formation pressure while drilling and reservoir zonation. The case study in this paper shows that with current advance technologies, incorporated data for available wells, and real-time technical support, the demands of sourceless drilling can be achieved to place the well in a precise target during slim borehole drilling.

The wellbore friction, torque and drag, between drill string and the wellbore wall is one of the most critical issues which limits the drilling industry to go beyond a certain measured depth. For this reason many studies on torque & drag modeling have been performed. In this regard different approaches have been used; the difference in these approaches is often on how to include bending stiffness and shearing forces in the T&D calculations. These approaches are (1) the effect of shear forces calculations with the assumption of continuous contact of the wellbore wall and the drillstring as well as constant curvature trajectory, (2) the effect of bending stiffness and shearing forces calculations with assuming of clearance between drillstring and wellbore-wall and (3) the effect of bending moment and shearing forces, assuming continuous contact of the pipe and wellbore-wall and using a non-constant curvature trajectory in which the first and second derivatives of the curve exist (i.e. spline type trajectories). This paper consists of two main parts: first a review on literatures on the subject of stiff-string T&D will be considered. Secondly, an approach will be discussed in which despite of the assumption of constant curvature trajectory and full-contact of pipe and wellbore wall, the effect of bending stiffness on torque and drag calculations are considered. The simple and robust stiff-string model is implemented in two example wells in order to find out the importance of the stiff-string calculations.

Most area of North Azadegan oilfield is covered by wetland, especially, in the north part it is covered by reed marshland with 1.5-3m deep water. Meanwhile, there are lots of landmines left during the Iran-Iraq war. It is expensive to construct pads in this area (more than 300 million dollars for one pad). In order to protect environment, decrease dangers to construct pads and save cost on building pads, cluster well is the first choice. In this paper, well network was optimized first based on geological requirements and environment limits. Formations upper 800m are unconsolidated, 800m-1000m mainly are shale and more stable, Gachsaran contains bout 1800m salt-gypsum in lower part with high formation pressure about 1.8g/cm 3 and high pressure salt aquifer with EWD up to 2.31g/cm 3 . Two plans for kick off point of horizontal wells were considered, in the interval 800-1000m or below Gachsaran. Multi-well anti-collision and avoidance of obstacle were considered and the well profiles were optimized. 15 well pads for cluster wells were designed: 5 pads with 5 horizontal wells, 1 pad with 5 horizontal wells and 1 vertical well, 1 pad with 4 horizontal wells and 8 pads with 2 horizontal wells. This protects environment and saves cost expending on pads building to the maximum extent. After considering effects of KOP on dogleg and inclination and the downhole complications encountered in drilled wells comprehensively, kick off point was built in Gurpi formation about 2300m deep (below Gachsaran). Based on this, optimized the wellbore trajectory, BHA and parameters. By far, all the wells planed have been finished, there is no any collision accident, target hitting rate is 100%, drilling catching rate in reservoir is 100%, both the success rates of electric logging in horizontal interval and casing running in designed depth are 100%. The drilling experience and expertise in north Azadegan oilfield could be used for a beneficial technical reference for drilling in such complicated environment and complicated formations.

Step change in drilling effiency to enhance drilling performance in our field. Our casing design in our field heavy casing design as drill 22″ hole and set 18.5/8″ casing at +/- 2000 ft and drill this phase with RSS to control the verticalitly in the hole as our wells drilled in cluster location the separation between each wells is 10 M only so the verticalitly is very important to avoid anti collsions between the wellsso 1 st phase the quality to drill the hole and run casing is very important than make perfroamnce. Second phace in our casing design is 16″ phase which will drill it deviated section up to +/- 9000 ftand will discuss it in detail after complete discsions the remain phases in our casing design.

A pilot project was initiated by PetroChina-Changqing to test a new integrated drilling and fracturing solution for a tight oil reservoir in central China. The results indicated this new integrated solution is an effective way to access the tight oil with high production, even with permeability less than 0.2 md. The integrated solution included a horizontal well drilled with real-time image and near-bit measurements for accurate and timely well placement decisions, well placement technology for trajectory optimization, multistage fracturing technology to stimulate the tight reservoir, and a properly placed trajectory and updated geologic model to optimize the fracture design. With good cooperation between the service company and the operator, this pilot project showed favorable production results. Production testing on the first horizontal well showed initial production of 120 m 3 /day in contrast to the vertical well production of less than 1 m 3 /day. The real-time image clearly indicated the trajectory position in the sand and provided confirmed information for accurate trajectory adjustment. Well placement technology was successfully applied in the tight oil reservoir, with net-to-gross KPI of 100%, and the well trajectory placement met the specific exploration purpose. A 14-stage fracturing job was successfully executed, with 65% of the fluid volume flowback. Microseismic monitoring indicated that all of the intended reservoir was stimulated. The pilot project showed that the integrated drilling and fracturing solution using horizontal well technology was effective for a tight oil reservoir. This solution can be applied to other tight oil blocks to improve tight oil exploration and development.

Abstract J4 project was initially an 8 well small field development. Initial well designs were of 2 dimensional trajectories, a total depth of 7000 feet and a tangent angle not exceeding 60 degrees. Average well P50 drilling authorization for expenditure was calculated at 25 days. By definition of small field, the economics of the project was under management scrutiny with positive performance expected. After drilling the first J4 well and exceeding the AFE by 25% and the eventual loss of the platform slot while drilling the second well, it was apparent that a complete step change during planning and execution was required for the success of the project. For effective step change, the recently enhanced Performance Improvement Process (PIP) was used. PIP encompasses other performance enhancement methods providing the necessary tools to undertake problem solving in a methodical manner. Additionally, for PIP to be effective it was crucial to harness the experience, knowledge and uninterrupted contribution of the well-construction team. PIP was designed to complement the Core Workflow Process, a systematic method for well planning, well design, and well execution. Besides PIP measurement, the team would investigate the rate of return on investment made in the performance improvement process The J4 team was keen to highlight what level of investment in performance improvement was justified in the tight budgets of a small field development. As time was limited and the third well pending an assessment and rethink of the remaining wells by way of a structured fast track approach was essential. This would be the first time PIP would be applied to accelerate change to a project in Petronas Carigali SDN.BHD (PCSB). PIP provided the structure and format to enable the team to embark on a comprehensive examination of the geological data, update the geological model, and re-design the projects remaining wells and trajectories through to their successful execution. This paper will discuss the PIP tools, methods and practices utilized by the well construction team to successfully fast track and improve drilling performance while returning a positive return on investment for the changes made. Introduction J4 well designs were engineered around the subsurface and offset well data available. Provided such data is definitive then well planning and design can be conducted with a view of confidence. J4 well planning and design phases was carried out utilizing the Core Workflow Process (CWP), refer to Fig.1.The CWP ensures that the optimum well design and well programme is developed while all risks are identified and managed during the process. A "review gate" principle is employed to assess and optimize each key milestone during the planning stages. CWP can be utilized for a single well or for a campaign of similar wells. It is designed so that it can be adapted as necessary to address the technical and commercial risks associated with the well or campaign and any business requirement. The process can also be used to "fast track" a project. Benefits of the process are intended to Create value to the business and stakeholders maximizing return on investment. Establish accountability at key milestones where a consent or discard principle is applied based on the considered risks versus the value being proposed by the project team. Implement effective risk management to identify and lessen the risk of HSE incidents and project de-railment. Implement effective quality assurance throughout each of the review gates. Promote multidisciplinary teamwork and integration within the project team.

Abstract Earlier attempts to establish DD performance using the directional drilling difficulty Index (DDI) proposed by Oag & Williams 1 is flawed and difficult to interpret. The philosophy behind the DDI relationship is based on the perception of a sample space. Thereafter a mathematical relationship between the "perceived" variables identified within the sample space was proposed. DDI can only be applied for performance benchmarking if the planned DDI can be related to the actual DDI. DDI can only be used to compare the difficulty of drilling wells from the same terrain and to similar vertical depths. Since DDI does not consider adherence to the plan to account for differences between plan and actual drilled paths it therefore does not provide much information in the way of performance monitoring or benchmarking. Is there a need for directional drilling performance monitoring? Is it possible to isolate other methods of measuring performance such as finance or time based relationships? Are we able to demonstrate directional drilling performance in such a way it becomes possible to eliminate the impact of differences and variations in service prices, service tiers, competency of rig crew and rig capability, terrain, etc? This makes the cost based approach quite restrictive in its application in establishing a key performance indicator for directional drilling activities. Traditional methods 2 for measuring performance use metrics such as cost/foot, cost/10000 metres or feet, NPT distribution, ratio of NPT-to-Exposure time for specific services, $/BOe and days on well to name but a few. Generally, the metrics are designed either as time or cost based relationships. The implication there of is that directional drilling competency or performance is somewhat lost within the generalized approach this method requires where information is normalized into time or cost based variations. Therefore, directional drilling impact on the drilling cycle becomes a measure of how quickly the well is drilled with little or no consideration on how to get there and the impact of the tortuous part drilled on the outcome and performance of the well. This paper does not suggest the elimination of traditional methods but looks at ways of establishing a performance metric between the values 0 and 1 that can be used to compare directional drilling performance whilst still capturing the essence of time and cost based relationships. Furthermore, this method becomes extremely easy to use and can be easily computed at the well site using a simple spread sheet solution as the inputs for each well can be obtained from the standard directional survey file and the daily drilling reports. The application of the results include benchmarking performance from well-to-well, across projects, contractors and fields and to understand the influence of directional driller competency and geology on the final performance indicator. Introduction Directional well surveys are defined by the following: Surface location usually expressed in terms of a geographical or UTM co-ordinates A subsurface target which is also defined by specific co-ordinates which are usually not the same as the surface location unless in specific cases. This is also further defined in terms of a target tolerance around a specific vertical depth reference. The standoff between the surface location and the subsurface target(s) usually establishes the DLS (or BUR in case of a 2D well) requirement, the directional well path which includes inclination and azimuthal variations and the sail angle through the target(s).

Abstract PDVSA Múcura District, jointly with the drilling department and the service companies, had been evaluating for several years the use of new technologies that facilitate reaching reservoirs with complex geologies (thin sands, uncertain dip changes, and unconsolidated sands) and improve overall operational efficiency. Additionally, because of the high viscosity of the oil contained in the Bare field, it was necessary to apply thermal methods to increase recovery factor and achieve PDVSA's 20% target. In such thermal processes, the placement of the wells within the formation is very important, and the use of well placement techniques is expected. Looking at demonstrating the benefits of the state-of-the-art technology available, specifically for Bare field, but generally for the heavy Orinoco oil belt, PDVSA carried out a pilot project in a thin and very unconsolidated package where a very high drilling rate (up to 1,000 ft/h instant rate) was expected. The selected sand is named the TL sand, located in the Oficina formation of the Bare field, was initially planned for cold production, but expected the implementation of future thermal enhanced oil recovery processes. Introduction The Faja extraheavy oil belt in eastern Venezuela is one of the world's largest heavy oil accumulations, containing an estimated 1.3 trillion bbl of original oil in place, in which 300 billion bbl are considered recoverable oil. The Orinoco oil belt is located on the southern margin of the eastern Venezuelan basin and runs along the north side of the Orinoco River for approximately 600 km in length and 90 km in width, totaling an area of 55,000 km 2 . The area is divided, from west to east, into four blocks: Boyaca, Junin, Ayacucho, and Carabobo. To recover such reserves, PDVSA needed to explore and develop the reservoirs in an economical and efficient manner and increase the current recovery factor. The two major challenges found in the Orinoco belt are the development and exploration of thin sands and the current low recovery factors of approximately 3% expected by primary recovery. From one side, thin sands in the Orinoco oil belt represent 30 to 40% of the oil in place, which is located in a deltaic sequence with sand thicknesses of less than 20 ft. This challenge is difficult to overcome with conventional technology. The thin sands have to connect larger sections of horizontal sand intervals by drilling geologically referenced trajectories.

Abstract Traditionally, the steering of horizontal wells has been based on logging-while-drilling measurements that rely on the sensors to actually measure the formation's characteristics when drilling through it and then use this information to make the correct steering decision. This approach is a reactive one, however. The implementation of deep and directional electromagnetic measurements that can detect approaching boundaries enables us to implement a proactive steering approach. Another key element of the new approach is the ability to make geosteering decisions to change the well trajectory in both inclination and azimuth. This is a critical success factor when dealing with a channel sand environment, where the shape of the sand bodies is not well delineated by seismic data. This challenging work calls for multidisciplinary collaboration and integration of techniques to succeed in maximizing the net-to-gross ratio obtained from drilling horizontal laterals in such environment. Similar collaboration has been facilitated using a workflow that helped the geosteering operation run effectively, even within a large geosteering team from different backgrounds and companies. In this paper, we look at case studies where the new technique has been implemented. We discuss aspects that lead to the success of this approach and the learning points gathered from the case studies are presented as well. Introduction As demand for energy grows, pressure is mounting to extract as much hydrocarbon as possible from old and new reservoirs. The industry is under pressure to improve recovery factors. One key element that is fundamental in achieving higher recovery factors is improving the net-to-gross ratio of horizontal wells. Doing this can be only achieved by increasing the success rate in making reservoir contact while drilling. To maximize reservoir contact the industry moved from vertical wells to horizontal drilling. As more horizontal wells are drilled in difficult and complex reservoir targets achieving reservoir contact becomes even more difficult. This is coupled with the fact that many of the easy oil and large thick reservoirs have been already drilled and now smaller, thinner and more complex reservoirs are now considered given the current demand level and oil price. To adapt to the changes described above the level of understanding at various stages of the field development has to come to a level that matches the challenges in hand. Our level of understanding at the planning phase and while constructing the wells will have to improve if we are improve our net to gross when drilling horizontal wells in thin and complex reservoirs. The paper aims to demonstrate areas of improvements in the geosteering techniques and how such improvements impacted the net to gross which is critical to boost recovery especially in such complex clastic environment. Four aspects highlighted and discussed. The fist aspect is the proactive approach in geosteering which means the ability to make a geosteering decision early before exiting the reservoir. The second aspect is related to the ability to see reservoir boundaries if approaching from any direction. The third aspect is the power of the integrated workflow of the geosteering process including the planning phase. Finally 3D visualization aspect is considered.

Abstract This paper describes the successful introduction of ultraslim rotary steerable system (US-RSS) drilling in Saudi Arabia. A case study is presented where a 2167 ft power water injector redrill lateral was successfully drilled in the reservoir using an US-RSS on 2 3/8" drillpipe in conjunction with ultraslim logging-while-drilling tools, which were used for concurrent high accuracy geosteering. The existing casing design required that the sidetrack had to exit the liner in the reservoir section, since sidetracking higher up was not an option because of the risk of exposing problematic formations and pressurized zones. A number of challenges had to be overcome, including engineering design for sufficient weight transfer to be able to drill and good bit selection, since it would have been impossible to drill the planned section with a motor or conventional drilling assembly. Each stage of the job was carefully planned in detail and all stakeholders were briefed and contributed to the plan to ensure that all objectives - both drilling and well placement, could be met. The US-RSS was run in hole to drill the lateral, which was drilled with a 3 7/8" bit and concurrently opened up to 4¼". The US-RSS tool performed as planned and produced an overall rate of penetration (ROP) of 28ft per hour in a single run during the geosteering operation. All well objectives were achieved, and the system clearly demonstrated a robust technical solution to the problem. The US-RSS will enable greater reservoir access, especially in the redevelopment drilling application, and when used in conjunction with ultraslim LWD tools, can also be used to place the well in the best position for optimal additional production. Recovery rates from the field are now expected to be enhanced as a result of this technology, and without the need for drilling further new wells. Introduction Today it is well understood that further opportunities exist to enhance the production from existing fields 1 and to access as-yet untapped areas of the reservoir using a variety of redevelopment drilling techniques. Saudi Aramco faced this challenge with a re-entry program to redevelop an average of up to fifty wells annually in some of these fields, in order to recover as much remaining oil in place as possible. Due to the existing casing design and the formation pressure profiles, the only feasible size for the new drain hole is 3 7/8" diameter, if the existing well architecture is to be used for the redrilling program. However, this hole size is known to be problematic from a drilling perspective in terms of pipe buckling, achieving effective weight transfer to the bit, and the physical limitations of the mud motors that are available for this hole size. This is especially the case with regard to directional control, where the length of lateral that can practically be drilled with the motor is limited by the ability to 'slide' to control the trajectory and maximize the reservoir contact. These issues also result in roller cone bits having to be used to drill in this size, resulting in several trips per hole section, and therefore a lot of 'dead time' being required to complete drilling each well. An alternative approach is to use the recently developed US-RSS to complete these redrill laterals in a single run by rotating continuously while steering, thereby reducing the impact of the buckling forces, and by using a PDC bit. In addition, such a solution to the problem would also conceivably allow for longer laterals to be drilled while staying in the desired layer of the reservoir, thereby giving potentially greater access to the remaining oil-in-place. The US-RSS tool was developed for drilling in this range of hole sizes, specifically for this application, and can be used as part of a standard drilling system run on drillpipe. The system can also be used for coiled tubing drilling applications for 'thru-tubing' drilling 2, which has been documented elsewhere.

Abstract In the work environment of continuous improvement as a method to reduce both drilling and production costs, alternative means are required to attain objectives which have previously been deemed unachievable. The introduction of new tools and technologies has enabled increasingly challenging wellpaths to be drilled and completed. Trajectories labeled as undrillable even a few short years ago are now being realized. The high cost and environmental concerns associated with offshore installations and the resultant requirement for drilling multiple wells from a common facility, has been a significant driver in the field of extended reach drilling to drain reservoirs with significant step-out. Sub-surface geological issues and wells with multiple targets have resulted in complex 3D well trajectories such as ‘pregnant lady’, ‘snake’ and ‘dragon’ wells. Within the above context, Brunei Shell Petroleum (BSP) has identified that by drilling ‘fishhook’ shape wells, whereby a large section of the wellpath is drilled and completed at an inclination greater than 90º, significant savings in both drilling and production costs can be achieved. This is a case study of such a well drilled in mid 2004, whereby some 875m, or 35% of the total well trajectory was drilled at an inclination greater than 90º. The well also required 7" casing to be run and cemented to well TD, sand control in the form of Frac and Packs, and Expandable Sand Screens (ESS) run across three reservoir zones, with isolation between each zone. Maximum inclination was 126.5º, and some 366m true vertical depth (TVD) reclaimed. Introduction The Darat asset for BSP is comprised of onshore and near shore hydrocarbon producing fields, principally the Seria field. (Fig.1). It is a very mature field, having produced in excess of 1 billion barrels of oil since the field came on stream in the 1930's, with significant additional development opportunities identified. The near shore target reservoirs exist in extremely compartmentalized, highly stratified blocks. Due to the nature of the faulting in this shallow marine area, many of the blocks dip towards the coast and are comprised of multiple sand-shale sequence reservoirs (Fig.2). Historically wells targeting these reservoirs have been drilled with offshore units and require the installation of well jackets and subsequent flow lines. By drilling these wells from land, the cost benefits of using a light land rig as compared to a jack up rig, and the associated greatly reduced production costs can be realized. There are also other factors such as environmental issues and HSE exposure to be considered. However, due to the south-hading normal faults (dipping towards the coast) and the relative shallowness of the target reservoirs, in order to intersect the multiple targets contained within each block from a land based surface location, a well trajectory that builds from vertical, through horizontal and continues to build resulting in the ‘fishhook’ shape is required. Essentially it is an upside down fault-scooper. To clarify the ‘fishhook’ definition, there are many examples of wells drilled worldwide, particularly horizontal geosteered wells, where inclinations of greater than 90º have regularly been achieved to maintain well trajectory within the target reservoir. To be a true ‘fishhook’ well, trajectory inclinations substantially above 90º must be achieved and sustained for a significant interval, resulting in vertical depth reclaimation in excess of 100m. i.e. the vertical depth gain between the deepest point in the well (TVD) and the shallowest point once the well path has passed through horizontal.

Abstract Achieving the objectives of drilling horizontal wells is greatly dependent on accurate placement of the drainhole in the reservoir. Careful pre-job planning using offset well data and seismic maps helps to reduce the uncertainty to some extent. However, the unpredictability of structural and stratigraphic variation between the planned and offset wells and uncertainty inherent in seismic data are always associated with horizontal well planning. The formation dips computed from seismic and offset wells are therefore prone to some degree of error. Advances in real-time data transmission technology have made it possible to transmit image data uphole while drilling, through improving the robustness of the real-time signal, signal bandwidth and data compression. Logging-while-drilling (LWD) real-time azimuthal resistivity images can be used for accurate estimation of the dip and strike of formations intersected along the well trajectory. In addition, structural surprises such as faults can be detected, and remedial actions taken immediately. Such information is of great value in making geosteering decisions while drilling into reservoirs within structurally complex geology or in an area with sparse geological information. Using image data, trajectory adjustments can be made during drilling yielding optimal well placement. We descibe the use of real-time image interpretation during the drilling of two horizontal wells within a block bounded by major faults on the north and south, with a series of smaller associated faults, anticipated but not confirmed prior to drilling from existing data, in a carbonate field in United Arab Emirates. The image data provided crucial input to guide the well trajectory through the target reservoirs resulting in the wells objectives being achieved. In addition, the image data clarified the regional geology of the area around the wells, thus helping to update the geological model for better description of the structurally complex reservoir. Introduction The subject field is located onshore Abu Dhabi in the United Arab Emirates. Production is from an alternating sequence of high and low porosity calcite layers. To minimize the environmental impact of the field development, the wellheads are clustered, thereby keeping roadworks, piping and other obstructions at surface to a minimum. As a result of this surface clustering the wells are drilled away from the location of the cluster and then turned parallel to the maximum formation stress orientation. Early development of the field involved drilling clusters of wells on either side of a fault corridor that runs through the field. Figure 1 shows the existing wells (red lines) drilled from surface clusters and the faults (black lines) indicating the presence of a fault corridor through the field.

Abstract We examine how well completion design is governed by subsurface characteristics, surface environment, and state of technology. We present a methodology of well design that takes into account geology, drilling, reservoir, and operational characteristics and constraints. The method selects pertinent configurations for well trajectory, formation completion, and wellbore components to segment, route, lift, and monitor the flow stream. We discuss how this methodology is derived from case histories in land, platform, and subsea fields. Introduction Various developments in the E&P scene have motivated this work on well completion design and its underlying methodology. First, the move to frontier fields and deepwater developments, where the subsurface and surface environments are complex and well numbers are limited, highlights the critical role each well plays in the overall performance of the field or asset. Second, in the vast number of mature fields, in which production is constrained by facilities, efficient well design is arguably the most effective means of enhancing field performance and stemming production bottlenecks from the source. Third, a wide range of drilling, completion, and production technologies have been developed in recent years in response to the increasing complexity of reservoir targets in developing and mature fields, which necessitates the development of a methodology to inform and guide the application of technology. (Prior work in this domain is partly reflected in References 1–6.) Finally, robust modeling techniques have been developed, primarily in response to technology developments, enabling a quantitative analysis of wellbore-reservoir interactions. 7 General Approach We place well design on a common footing with a broad range of engineering design problems, notably those in the process industry. A process plant is typically designed with a specified feed or inflow stream and a prescribed effluent or outflow stream. Experience and basic knowledge of a range of unit operations aid in determining the plant architecture that can reliably convert the inflow stream into the required outflow within the constraints of safety, economics, operability, and process efficiency. The blueprint of the process is captured in a process flow diagram, which becomes the basis of detailed design, component specifications, integration plan, etc. We decouple the well design problem into a high-level or conceptual design phase and a detailed design phase, and allow for iterations between the two. The object of conceptual design is to determine the well architecture that can most effectively convert the inflow stream from the reservoir to the outflow stream that can be handled by surface infrastructure. With process plants, however, the inflow stream is itself determined by the well architecture, particularly the segment of the well that penetrates the reservoir. As such, we may distinguish a ‘lower’ component within the well, which is the component that penetrates the reservoir and dictates the character of the inflow stream. The ‘upper’ component of the well, therefore, can be treated as the domain that converts an inflow stream from the ‘lower’ completion into an outflow stream that meets the requirements of surface infrastructure. The requirements of the outflow stream from the well depend on what lies beyond the well, and hence depend primarily on the field environment. Dry wellheads (land and platform) have very different delivery requirements than subsea wells (with a range from proximate wellheads in varying water depths to distant tieback and satellite wells). Thus, just as the subsurface governs the ‘lower’ completion, the surface governs the ‘upper’ completion. Given that the well is a conduit between the subsurface and the surface, this dependence is self-evident. Yet, there is a third dimension that impacts well design on a par with surface and subsurface characteristics.

Abstract Underbalanced drilling (UBD) technology has been gaining in popularity around the world because of its capability to reduce or eliminate formation damage, to increase production rates, and in some cases, increase the volume of recoverable reserves. The technology is applicable to fields where formation damage is a concern or where problems such as severe fluid loss, differential sticking, steering problems or slow drilling rates are encountered with conventional drilling. With underbalanced drilling, the formation pressure is greater than the hydrostatic pressure, allowing hydrocarbons to flow into the wellbore during drilling. This prevents potentially damaging drilling fluids and drilled fines from penetrating the producing formation. In previous experiences in the field using traditional drilling methods, considerable formation damage had been experienced, and although UBD had never been attempted in the area before, Brunei Shell Petroleum and its government partner decided to use this technology in a three-well trial in the Rasau field, located onshore in Kuala Belait, Brunei. Of the three wells attempted during this UBD trial one well could not be drilled due to catastrophic borehole collapse. The other two wells were successfully drilled to depth using UBD techniques; however, multiple hole volumes of solids were produced during drilling and production testing, indicating borehole stability problems. Production rates observed after drilling to TD and prior to running completions indicated zero formation impairment, with well productivity exceeding expectation; however, during the completion phase, mechanical problems occurred, and post completion well tests indicated productivity reductions of 60 to 70% compared with the pre-completion tests. This paper discusses the planning, drilling, results, highlights, and lowlights from this UBD trial, along with learnings and recommendations for future application of the technology. The execution of the program led to a sharp learning curve, and the development of recommendations that can be applied to future operations in this field. These primarily relate to well (construction) design, drilling procedures, equipment design, rig-up and rig-down optimization between wells, and completion design. Introduction The Rasau field structure is a local accumulation in a major anticline ridge extending from Miri, Malaysia to Seria, Brunei. The accumulation is divided into two fault systems, one trending in a southwest to northeast direction and the other in an east to west direction. The Rasau field has been on production since 1983 and there are currently 27 producing wells. The sandstone reservoirs are generally of moderate quality (1–100 md), and are of shallow marine origin, resulting in a laterally extensive stacked sequence. The producing reservoirs, typically located at a depth of 4900ft - 6500ft, contain saturated light oil (40°API) with varying sizes of gas cap. The drive mechanisms are reservoir specific and are typically a combination of gas cap expansion, solution gas drive and aquifer influx. To date, there have been no secondary recovery schemes implemented in the Rasau field. The 3-well trial project incorporated several major challenges that had to be addressed through the initial planning / design phase and risk/hazard assessment processes. To minimize formation damage and reduce cost, produced oil and gas were chosen as the drilling fluids. The wells were drilled at high angle through the target reservoirs, cutting through the many thin layers of pay to maximize formation exposure. Due to the layered nature of the reservoir, a moderate amount of shaley formation was expected within the planned trajectories (up to 50%), the stability of which was to be assessed as one of the trial objectives. The stability of this material was to prove a key factor during the underbalanced operations, and is thought to have been the cause of significant problems due to borehole breakout and collapse. Fig. 1 shows the location of the Rasau trial wells, and Fig. 2 shows the trial-well trajectory.