Recently two multilateral horizontal wells have been completed offshore using dedicated multistage hydraulic fracturing completions. The first well, located in the Central North Sea (referred to as ML-CNS), was stimulated using acid fracturing; while the second well, located in the Black Sea (referred to as ML-BKS), was stimulated using proppant fracturing. This paper presents the different drivers, challenges and lessons learned for each well while emphasizing the well construction and stimulation methodologies developed for the different reservoirs and field characteristics. The field development drivers for drilling and completing these offshore hydraulic fractured multilateral wells, a first of their kind globally, was different for each case. The objective of the first project, initially considered uneconomic, was to engineer a technical solution for completion and production of two separate reservoirs with only one subsea well. The second project was seeking to optimize infill drilling from the last available slot on the offshore platform to maximize reservoir contact and production in the same reservoir. ML-CNS was a TAML Level 2 completion with a 14-stage, 5 ½" multistage completion run in each lateral and set-up for sequential acid fracturing. Operationally, the first lateral was drilled and stimulated, followed by the drilling and stimulation of the second lateral, using the drilling whipstock to navigate through the multilateral junction. ML-BKS was a TAML Level 3 completion that had a 6-stage, 4 ½" multistage completion installed in each lateral, which were proppant fractured following a sequence designed to minimize the jack-up rig time required. Both legs were drilled and completed prior to starting the stimulation, access to either lateral was achieved with the existing workover unit on the platform by manipulating a custom designed BHA. The lessons learned from the first project executed in the North Sea were able to be transferred and applied to the second project in the Black Sea to allow for a more efficient and confident completion solution. Led by varying economical and regional constraints, the key factor for both wells centered on delivering operationally simple and reliable multilateral completion designs to economically meet the field development strategy in place. To the knowledge of the authors and following subsequent literature research, both wells are a worldwide first for an offshore multilateral well completed with multistage acid fracturing and multistage proppant fracturing, and together they represent a new trend in cost-effective offshore field development through well stimulation. The successful case studies for both wells with the combined analysis of the benefits, challenges, and lessons learned will provide a guide and instill confidence with operators who find this approach beneficial with a view to applying it in other assets.

In 2012, a benchmarking exercise was conducted to assess the performance of Bonga wells, a Deepwater (DW) project in Nigeria. The review revealed that the average Bonga well ranked fourth Quartile when compared with similar DW wells globally. After reflecting on the benchmark results, the Bonga Wells team concluded that something drastic needed to be done urgently to reverse the trend otherwise future projects will become unattractive and the profitability of the Bonga Field will be impacted negatively. Late 2012, a clear steer was given by Bonga Wells Leadership to reverse the performance trend. The mantra for the team was to beat the best performance anywhere in the world and there was a very strong leadership commitment to make it happen. The team concluded with a target to deliver ‘best in class' wells consistently within 24 months.

Currently, real-time adjustments to drilling parameters such as weight on bit (WOB), drillstring revolutions per minute (RPM), flow rate, etc., are based primarily on experience. This is mainly due to the uncertain nature of information (both downhole and surface) available and inability of humans to aggregate multiple data streams in real-time to make optimal decisions. The objective therefore is to build a decision support tool that can overcome these limitations by automatically aggregating this data, identifying drilling inefficiency and suggesting optimal drilling parameters. The methodology presented in this paper uses a Bayesian network to represent the drilling process and is capable of representing uncertainty in a way that is robust to bad sensor data. The model is updated in real-time and tracks variations in drilling conditions. Various dysfunctions such as bit balling, bit bounce, whirl, torsional vibrations, high mechanical specific energy (MSE), auto-driller erratic behavior, etc., are identified by tracking the movement characteristics of various sensor data in relation to model predicted values. A holistic drilling optimization index is thus derived by aggregating all this information. This index coupled with the drilling dysfunction prediction ultimately enables recommendation of drilling parameter corrections. The drilling optimization index has been integrated into a drilling rig data aggregation system currently in operation on twenty rigs in North America. The system has access to real-time data, both at low frequency (less than 1 Hz) as well as data in the 1 to 10 Hz range, and also contextual data (such as data typically available in a tour sheet or well plan). In deploying the system, human factors aspects were given significant consideration. A typical driller is not familiar with concepts such as Bayesian networks, MSE, etc. By displaying the effectiveness of drilling as a single, dimensionless parameter, an index that varies between 0 and 1, with 0 representing inefficient drilling and 1 representing optimal drilling, the message is effectively communicated to the driller. The index is currently depicted in a very intuitive "speedometer" type of visual. Values are low and closer to 0 when dysfunctions occur, and when that happens suggestions are provided on how to mitigate the dysfunctions. These suggestions are visually presented in the form of operational cones in the WOB-RPM space. Additionally, the variation of the index with drilling depth is displayed to enable the driller to identify how formation changes impact drilling performance. This was found to be useful to drilling engineers who are generally tasked with optimizing the drilling process.

As part of the planning for development drilling on the North Sea Catcher fields in 2015, Premier Oil sought technology solutions that would aid in drilling the complex injected sand reservoirs. Due to the highly variable and potentially discontinuous nature of injected and remobilized sand reservoirs, operators have historically had to drill multiple sidetracks and the utility of drilling pilot holes to reduce depth uncertainty was of particular concern. Pilot holes in injectite reservoirs have seen variable success, as the positional information obtained can only be extrapolated over short distances due to rapid changes in reservoir form and stratigraphic position. The complex 3D architecture of injectites also poses challenges in drilling horizontal wells, leading to difficulties in optimizing well placement, with an increased risk of having to carry out a geological sidetrack, and an increased risk of sidetrack failure due to missing reservoir or shale instability. Moreover, pilot holes and sidetracks come with their own drilling challenges, be it technical or financial. To help de-risk these challenges, Premier Oil selected the Deep Directional Resistivity (DDR) logging while drilling tool to map and to help understand these complex injectite reservoirs. With a depth of investigation of up to and in excess of 30m (100ft) TVD from the wellbore, the service enabled the Premier Oil and Schlumberger Well Placement team to map the injectites complex external geometries and internal architectural features in real-time. Being able to resolve the form of the injectite reservoir in real-time provided the team the ability to use this wellbore-to-reservoir scale information to tie the position of the reservoir to the seismic data. From this it has been possible to forward project wellpaths and make informed geosteering decisions as wells drill ahead and new data is acquired. This ability to map and proactively geosteer, both on landing and within reservoirs in real-time, has helped Premier Oil to avoid both pilot holes and geological sidetracks. In this paper three case studies are showcased. The first case demonstrates how the requirement of a pilot hole was eliminated by using the DDR technology. The second and third case studies illustrate the quantitative assessment of sidetrack risking and how data collected during drilling enabled optimum well placement via azimuthal geosteering and hence the avoidance of a possible sidetrack during the horizontal reservoir sections.

During the late life of the Siri field in the Danish North Sea, an infill water injection well was drilled to provide enhanced reservoir sweep and to help improve tail-end field production. Dynamic reservoir modeling indicated that a down-dip horizontal water injector on the southwestern flank of the field using injection inflow control devices (ICDs) could provide the necessary uplift for producers near the crest of the field. The Siri field is characterized as a high permeability, remobilized glauconitic sand package comprising multiple stacked and amalgamated sand bodies deposited from high density gravity flows in the Paleocene-Eocene Siri fairway. Seismic, well logging, and production data indicate that fluid flow is influenced by vertical and horizontal baffling. The internal flow channeling and baffle effects are likely caused by a combination of siliciclastic diagenesis, subseismic faulting, and multiple calcite-cemented paleo oil/water contacts. These baffles are capable of maintaining significant pressure differentials. They consequently have a major effect on field scale horizontal permeability and reservoir sweep efficiency. During the last decade of drilling horizontal development wells in the Siri area, Dong Energy has obtained extensive in-house experience and knowledge in the use of deep reading resistivity technology for reservoir mapping, as well as in positioning long horizontal development wells in challenging settings, such as ultra-thin reservoirs sands and thin oil columns. This paper discusses the well placement and geological evaluation of the Siri reservoir with regard to the acquired logging while drilling (LWD) data, which includes resistivity inversion, neutron porosity/bulk density imaging, and formation pressure measurements. The well trajectory was adjusted in real time to reduce footage exposure to tight facies, as well as to identify fluid boundaries related to the flow channeling present within the reservoir. Borehole resistivity inversion provides evidence that the mineralized permeability barriers are not always high-angle features. This paper also discusses insights into the Siri reservoir geology in light of the horizontal well data acquisition program and potential implications for future ICD behavior.

The Cygnus gas field is being developed by ENGIE E&P UK Limited in the UK Southern North Sea and is one of the largest discoveries in the Southern North Sea in the last 30 years. The field has two gas bearing reservoirs in the Carboniferous Lower Ketch Member of the Ketch Formation and the Permian Lower Leman sandstone. The Lower Leman Sandstone is the main reservoir target for 7 of the 10 wells in the development. The Lower Leman Sandstone is highly layered comprising fluvial influenced playa shoreline facies. The better reservoir quality intervals are restricted to thinly bedded laterally extensive sand rich intervals related to drier climatic events. Through utilization of reservoir navigation LWD tools the production wells have preferentially targeted these better quality thin intervals in order to maximize well productivity. To geosteer in these sands provided several challenges such as uncertainty in dip and the presence of sub-seismic faults. Furthermore the reservoir shows only subtle variations in log response from Gamma Ray and resistivity tools. This made correlations with offset well data difficult. As a result, the integration of information from multiple LWD tools and types of analysis was required to delineate the geological structure and to identify the stratigraphic position of the trajectory in order to place the well in the target interval. The key data sources for the leman productions wells have been the correlation to offset data, real-time Density images and utilization of Deep Directional Azimuthal Resistivity's. The limit of the Deep Directional Resistivity tool was tested due to the very low resistivity contrast reservoir (commonly 1-2 Ohm.m) but the data has still been utilized during geosteering operations. The quality of the density image data has also allowed for a real-time True Stratigraphic Thickness (TST) calculation service to be provided where extra stratigraphic control was required. Five of the Leman production wells have been successfully drilled and completed with results that were at the high end of expectations. This will contribute to maximizing the productivity for the field. In this paper the case studies showcased will demonstrate the Geosteering methodology utilized in this complex reservoir. For ENGIE, these examples demonstrate the value of investing in technologies for acquiring multiple data sets for successfully Geosteering in challenging geological settings.

Shallow oil reservoirs, commonly associated with heavy oil, require massive completion programs. The reason for these huge completion programs is due to the need for larger hole sizes compared with standard borehole developments. The commercial feasibility of these developments relies on repetitive and predictable drilling performance in large hole sizes and high-angle curvatures to reach very soft formations. One such development is the Mariner field in the UK sector of the North Sea, which was discovered 30 years ago. This field, located 140 km east of the Shetland Islands in 110m water depths, is the largest new field development in the UKCS. Two targeted reservoirs contain heavy oil in shallow unconsolidated sands in the Maureen and Heimdal formations. Field objectives included the following: 100+ well targets at the rate of ± 12 wells per year Timely well delivery schedule Technology application to lower Drilling &Well operations sanctioned cost by at least 25% The construction program for the Mariner field required the 20-in. casing shoe to be set at a shallow true vertical depth subsea (TVDSS) of ±750m, at inclinations between 35 and 55°, and build rates of 3 to 5°/30m in the ultra-soft formations with an unconfined compressive strength (UCS) of < 1000 psi. Although the advancements made in rotary steerable system (RSS) technologies are capable of generating 15 to 18°/30m dogleg severity (DLS) output, these technologies have historically been confined to small hole sizes extending from 5⅞ in. to 9½ in. This paper describes the development of the world’s first RSS bottom hole assembly (BHA) design, capable of delivering repetitive and predictable performance to drill large hole sections to high inclinations in shallow, ultra-soft formations.

Multilaterals are often cited as technology that can be implemented to maximize reservoir recovery rates. However, few operators have been willing to put multilaterals into practice. The most frequently cited reason for not considering multilaterals is risk. This paper presents a study of data from 22 years of actual multilateral well applications that demonstrate the reliability of the technology. For the purpose of this study, failure has been defined as the loss of either the lateral or main bore or the loss of the junction (and therefore access to both legs). In the context of this study, reliability has been defined as the ability to successfully construct and complete the multilateral junction. Where failures have occurred, a study to determine root cause(s) has been undertaken. The records of one multilateral service provider have been analyzed from more than 800 actual multilateral installations to determine success and failure rates. The reliability of multilaterals has been compared to the reliability rates of other wellbore completion and construction technologies. Multilateral technology (MLT), which was first implemented by Alexander Grigoryan in 1953, came into modern practice in the 1990s. Although it is not failure-free, the reliability of multilateral wells has improved remarkably during the past 22 years. This improvement in reliability has occurred as the complexities of multilateral installations have increased. This paper shows that successful completion rates of multilateral junctions have improved from slightly more than 87% for the period of 1995 to 1999 (with more than 100 junctions completed) to slightly more than 98% for the current five-year period (with more than 220 junctions completed). This improvement is the result of continuous planning, development of and adherence to procedures, management of change, communication, and continuous improvement. This is the first known study of multilateral reliability that encompasses a large body of data over a significant time period. The results presented should enable operators to make fact-based decisions about the reliability of MLT and about whether or not this technology should be considered for implementation into resource development plans.

Directional wells and cluster wells have become a conventional drilling technique now, which is widely used in various types of oil and gas reservoirs. Each year, more than half of the total drilling are directional wells in China. The main work is not to aim the target area, but to track the reservoirs now. Geosteering drilling is an important technical approach to improve single-well production and recovery ratio, to achieve the “less wells more production” idea. China Geosteering Drilling System (CGDS), integrated the technology of drilling with logging and reservoir engineering, applies the near-bit geological and engineering parameters as well as controlling method to ensure that the wellhole trajectory can pass through reservoir and get best location while drilling. The wellhole trajectory can be adjusted and controlled timely according to the formation features measured by CGDS. The drilling bit is equipped with “eyes”, which can identify oil/gas layer during drilling. Since 2011, we have provided CGDS geosteering services in 29 horizontal wells in Songliao Basin. The total footage reached 18255m, and the longest footage in horizontal section was 1325m in single well, while the average sand penetration rate is above 85%. Comparing with the horizontal wells operated by conventional LWD tools in the same block, the results of the field application shows that the CGDS geosteering system can significantly improve sand penetration rate and substantially reduce the drilling duration. On the basis of introduction to the system, this paper focuses on comparative analysis of significant application effect of CGDS geosteering system for the heterogeneous reservoir in Putaohua Area of Songliao Basin, as well as the lessons learned. Helpful case histories will also be presented.

As the drilling technology has advanced, recent deepwater developments and explorations are currently taking place in Gulf of Mexico, Brazil and West Africa where deeper reserves of oil have become more accessible. The study of the subsea soil (e.g. soil investigation, positioning foundation design) is one of the activities required for the subsea field development. Electromagnetic tests, CPT tests, gravity, piston core or vibrocore samples are obtained by deploying down-hole systems from drilling vessels. However, because of the high costs and low availability of drill ships, and because ship and drill-string motion due to wind, currents and waves affect the quality of the drilling process, robotic drill rigs are currently more widely used. The following paper describes the MeBo200 as a novel underwater drill rig for geotechnical/geological explorations. The MeBo200 drilling rig is lowered to the sea floor and operated remotely from the ship to drill up to 200m into the sea floor at an ambient pressure of up to 400bar. It was developed in cooperation by MARUM Center for Marine Environmental Sciences (University of Bremen) and BAUER Maschinen GmbH. The complete system is transported within seven 20 ft containers. MeBo200 is a second generation of the MeBo, which was the first remote-controlled deep sea drill rig that uses a wireline coring technique. The weight of the MeBo200 is about 10 tons in air and 8 tons in water and therefore it does not need special drill ships to be managed reducing therefore the mobilization costs for worldwide deployment. The MeBo200 was deployed in the German sector of the North Sea in October 2014 to test the functionality of the seabed-based drill rig. Currently MeBo200 is being upgraded with CPT technology from A.P. van den Berg Ingenieursburo bv.

The Shearwater field is a deep, high-pressure, high-temperature (HPHT) reservoir located in the UK Central Graben of the North Sea. The current drilling campaign represents the first round of well re-entries into the field following a campaign of slot recoveries to facilitate sidetrack development opportunities. A high level of reservoir depletion (> 8000 psi) has resulted in significant changes to the drilling envelope that has added complexity to the drilling practices required to successfully exploit the remaining reserves. Managed Pressure Drilling (MPD) Technology was pursued as an enabling technology to navigate within some very narrow margins in the first well of the redevelopment campaign. MPD was implemented in conjunction with drill-in liner and wellbore strengthening technologies to successfully deliver this first well and prove the techniques required to prolong field life. To promote successful implementation of MPD in the target zone, the technology was employed in the previous hole section to gain experience with the equipment and procedures where pressure control was less critical. MPD was used to control bottom hole pressure to manage background gas and facilitate changes to equivalent mud weight. It was further used to minimise the effects of loss/gain mechanisms and enable drilling through a tight margin between pore and fracture pressure while reducing the risk of borehole instability and losses. The technology was also used to determine appropriate mud weights for tripping and provide trip margin to avoid swabbing while tripping. In addition, MPD was used to facilitate cementing in tight margins. This paper will highlight the multiple uses of MPD throughout the start-up of this current drilling campaign and key learnings enabling successful implementation of a new technology on the rig.

When kicking off at low inclination, static measurement-while-drilling (MWD) surveys are used to confirm the kickoff direction when free of magnetic interference from offset wells. However, as MWD continuous azimuth and inclination measurements have limited accuracy, the directional driller will not have confidence in the kickoff direction with continuous (dynamic) survey while drilling, thus requiring additional static surveys to be made, taking up precious rig time. In a novel continuous survey method used in a particular rotary steerable system (RSS), a six-axis survey was taken continuously, both while drilling and when static, with the survey sensors being housed in the RSS. This algorithm was first verified in a software simulator, and it was subsequently implemented and tested in hardware. The effectiveness of the new measurement method was field tested and compared against MWD static survey points. The field test result from multiple wells shows that the new near-bit continuous azimuth and inclination from the RSS is considerably more accurate than that of the axial MWD continuous measurements at very low inclinations of between 1 and 5 degrees. This unique measurement method has valuable applications, such as low-angle kickoff without using multiple static surveys as the directional driller can use the real-time continuous azimuth and/or toolface to accurately steer the well through crowded offshore platform environments. When drilling out of the shoe, this survey method will allow an accurate kickoff approximately 50 ft earlier than would normally be expected as magnetic interference is cleared, and thus saving the precious rig time needed to kick off. Additionally, the use of a continuous gravity toolface is possible without the need for static surveys, allowing accurate low-side sidetracks to be performed even in areas of high magnetic interference.

The cognitive skill of knowing what is going on around you and using that information to predict future events is vital for drilling for oil and gas on offshore installations. This skill is known as Situation Awareness (SA), influencing subsequent decision making and performance. Failures of SA have been identified in a number of high profile well control disasters, most recently with Deep Water Horizon in the Gulf of Mexico. Despite SA being researched in other high risk, high reliability industries, such as aviation and nuclear power, very little research has investigated SA within the offshore drilling environment. Accurate SA is vital for safe and efficient performance on the drill deck with drillers being required to have high SA of the working environment and of their fellow crew members. This research study uses cognitive task analysis techniques of observation and critical incident interviews to investigate drillers’ SA when working within a state of the art drilling simulator, with the goal of producing a framework of the required cognitive skills. As this is a new study, preliminary results will be discussed at the conference.

Casing, liner and completion running operations are key activities during the well construction process. Failure to reach the required setting depth may have a significant impact on well economics due to additional construction costs, deferred production and lost reserves. A substantial proportion of NPT (Non-Productive Time) associated with these operations is due to stuck pipe, and over many years the industry has made a concerted effort to reduce this. A new advanced advisory system has been developed to enhance the monitoring of running tubulars into a wellbore. This web based system integrates real-time data, analytical capability and informative displays to identify early warning indicators associated with stuck pipe, mud losses and other anomalies. The system has been used to actively monitor more than seventy casing, liner and completion running operations in offshore wells located in the Caspian Sea, offshore Trinidad, the North Sea and the Gulf of Mexico. Early benefits that have been realised include improved responses to stuck pipe early warning indicators, closer control of trip schedules, greater collaboration between offshore and onshore communities, and better informed and more impactful decision making. The system is currently being deployed at scale to offshore drilling rigs and is expected to bring additional benefits of standardisation, embedment of good practice and know how, and enhanced organisational capability. As the industry drills longer, deeper, and more complex wells, the installation of longer and heavier tubulars into close tolerance wellbores will be required. This means that a deeper knowledge of the underlying physics and a better understanding of the limitations of tubular running equipment are required. It is envisioned that this advisory system will prove to be a mechanism to gain deeper insights into the casing running process, generate ideas for better designs and drive enhanced operational decision making. This paper describes the concept, system design and infrastructure requirements. Case studies from various field deployments are illustrated and conclusions from experience to date summarised.

The Troll Field is located approximately 80 km northwest of Bergen in the Norwegian Sector of the North Sea around 65 kilometers west of Kollsnes, and is operated by Statoil. The field is comprised of the main Troll East and Troll West structures in blocks 31/2, 31/3, 31/5 and 31/6. Although the field historically had produced large amounts of oil, it is now also a major gas producer, as it contains approximately 40% of total gas reserves on the Norwegian continental shelf. The gas reservoirs that are 1,400 meters below sea level are expected to produce for at least another 70 years. Statoil, wishing to run a deep sidetrack from the mother bore of a multilateral well, decided to evaluate several zonal isolation methods and to combine this with intelligent well completion technology. Since this would be a "first time" Statoil Troll field deep sidetrack from the mother bore in a multilateral well application, regardless of the technology selected, a full scale test to qualify the technology for the application would be required. After evaluating several zonal-isolation methods, and their previous experiences with isolation concepts, Statoil decided to use a combination of intelligent well completion design with feed-through swellable packer technology. This combination concept would not only be the first intelligent well completion of its kind in the Troll field, it would also be the first ever Statoil use of feed-through swellable packers. Swelling and differential pressure tests were initiated using oil from the Troll field. The testing revealed that this type of completion exceeded the sought-after requirements for the project. This well design was then approved and installed on a semi-submersible rig without any HSE incidents and ahead of plan. The well was put on production shortly thereafter, and zonal isolation was confirmed by selective closure of the flow control valves. Additionally a second nearly identical completion well design was installed in May 2013. The paper will discuss the swellable packer design, qualification testing, planning, installation, and the results of the first intelligent completion with feed-through zonal isolation on the Troll Field.

This paper explores the importance of forward planning for on-station hotwork repair and demonstrates how major repair work scopes, traditionally requiring completion in dry dock, can be carried out while the FPSO is producing. Although in theory FPSOs can be taken off station, the reality is that this has huge cost implications and reservoir issues may also make it technically very difficult. Even if the FPSO has a detachable turret, dry docking is likely to result in a minimum of 8 weeks off station. While periodical dry-docking can be easily scheduled for sailing ships, FPSO operators are increasingly looking for solutions that will enable them to keep their asset on-station and in production for upwards of 20–25 years. This being the case, it is inevitable that regardless of advances in integrity management strategies, structural hot work repairs will be required on-station. Given the inevitability of the requirement for hotwork repairs to the hull structure, it is essential that details of how the work will be conducted are fully understood and agreed by all stakeholders long before it is necessary to start hotwork activities. The relatively small numbers of FPSOs mean that operators may have limited experience of hull structural issues and standard procedures, for example, confined space entry procedure, may not adequately address the unique issues presented by working in the enclosed but large space of FPSO tanks. It will be necessary to define and agree procedures for emergency response to incidents, IP rescue, fire and muster, isolation standards, boundary hotwork management and tank cleaning.

In 2010, the anti-vibration stabilizer was introduced as part of the drill string assembly to replace the traditional near bit stabilizer in Algeria. The tool acts like a stabilizer and centralizer while not generating the point loaded blade friction associated with traditional stabilizers. With 100% borehole contact, this tool has improved hole quality and reduced drilling vibrations in many applications. There are three important vibrational phenomena that can affect drilling performance. Torsional relaxation oscillations induced by non-linear frictional torques between the drill-bit at the rock surface result in the phenomina known as torsional stick-slip. Axial vibrations induce the drill-bit to intermittently lose contact with the rock surface, which is known as bit-bounce. Lateral vibrations are the most destructive mode of vibration and create large shocks downhole by causing the Bottom Hole Assembly (BHA) components to impact the wellbore wall. The anti-vibration sub is a tool designed to ensure efficient drilling by mitigating lateral vibrations as part of the required energy management. The effectiveness of the sub has been proven through the analysis of downhole data and Mechanical Specific Energy (MSE) comparisons. The anti-vibration sub enables a very high signal-to-noise ratio for MWD (Measurement While Drilling) tools, improves bit performance and borehole quality, reduces the cost per meter for drilling and the non-productive time required for conditioning the hole prior to setting casing. An analysis of the data and field results clearly demonstrates the value of this tool. The anti-vibration stabilizer has been successfully utilized in several applications and is currently standard equipment for most vertical well rotary BHAs in Algeria.

Previous theoretical formulations for sinusoidal and helical buckling of drill strings vary significantly and are mostly proposed for frictionless pipes without tool joints. Finite element analysis (FEA) methods have the ability to consider geometric details and large deflections. However, traditional FEA methods use shell or solid dimensional elements for this problem and are computationally expensive. In this paper, an explicit FEA based on beam and connector elements implemented in the Abaqus software is employed to study the buckling of drill strings in different wellbores. The wellbore geometry, stiffness, friction load, and friction induced torque are modeled using connector elements. A typical drill string in vertical, inclined, horizontal, and curved wellbores is simulated and the explicit FEA results for sinusoidal and helical buckling loads are compared to different theoretical formulations and experimental results in the literature. The effects of length, inclination angle and string effective weight due to buoyancy as well as the effect of tool joints in straight and curved wellbores is also studied and compared to present formulations and published experimental results. Overall, it is demonstrated that using explicit FEA can efficiently study drill strings buckling behavior in straight and curved wellbore conditions.

An operator in offshore South China planned to develop a new oil field comprising multiple thin oil-bearing zones. It was decided to develop the field by upgrading an existing drilling rig on a platform rig 6 km away to drill extended reach horizontal wells. The objective was to place long lateral drains in a thin-pay reservoir. However, the foreseen risk of high drilling torque against the backdrop of the drilling rig that has maximum 42,000 ft-lbf drilling torque capacity limited this option. In addition, subsurface challenges constrained the ability to access the target reservoir optimally for production and reserve recovery optimization. The latest fit for purpose logging-while-drilling applications were used to overcome the drilling challenges—limited rig capacity and subsurface challenges—in these extended reach horizontal wells and to optimize ultimate recovery and the economics of each additional well drilled. The efforts were performed in real time while drilling and aimed to place the well optimally within the thin pay zone by delineating and mapping the top and bottom pay zone boundaries simultaneously. With this ability, the lateral could be placed accurately without making unnecessary trajectory adjustment that can result in additional drilling torque. Two wells were completed successfully. Application of the technology resulted in significantly higher production compared to the set target. The reserve recovery was optimized by placing the well 0.5 m below the top. The drilling torque was minimized, thus increasing the ability to drill farther and capture additional reserves. Significant savings in total drilling cost were attained by ensuring smooth drilling operations free from unnecessary adjustment and sidetracks. A similar approach could address the challenges in other, similar complex and hard to reach reservoirs targeted in exploration and development activities in offshore operations.

It is very important to understand the mechanisms involved during the tripping job and to know about the factors that come into play during and after the tripping operation. There are a number of downhole parameters involved that can interrupt the normal tripping activity and can lead to serious well control situations, such as blow out. According to estimates in Louisiana, Texas during 1960- 1996, a total of 430 blowouts occurred during drilling, of which pulling out of the hole (swabbing) took the lead with 158 blowouts. In addition to surge and swab that might come into play, one of the unforeseen problems in tripping job is tight hole that in worse case can lead to stuck pipe and brings about major Non-Productive Time (NPT) of the operation. The causes of tight holes include: Formation related problems (tectonics, etc), borehole trajectory, insufficient inhibition, improper mud weight, lack of lubricity and inadequate hole cleaning. There are several problems that arise during tripping in/out in the wellbore but emphasis has been placed on tight hole in this study because of high financial impact the drilling industry encounters and downtime it poses during drilling operations. In this study this challenge that is associated with tripping operations (tight hole) will be implemented in a 3D Virtual Drilling Simulator for a field case in the North Sea and interesting results have been presented. In addition to invaluable results inferred, the 3D Virtual Drilling Simulator can be used to train a complete drilling crew for a specific operation (i.e. RIH & POOH and related challenges).