Several extended reach-restricted completion-smart wells required matrix acid stimulation using Coiled Tubing (CT). These wells are equipped with Mechanical Formation Isolation Valve (MFIV) in the tubing end which needs to be reopened by using CT to access mother-bore for performing acid job. CT simulation results for these wells showed coil can reach only 60-70% of open hole interval. Calibrated friction coefficients were used in CT simulation based on the data base developed from other wells in the same area. Only CT-Tractor simulation showed 100% reach with maximum tractor over pull of 3200 lbs from the lock-up depth. World’s slimmest CT tractor was developed in collaboration specifically to address the challenges of extending CT reach past lock-up depth during acidizing and other intervention jobs in minimum restriction extended reach well. The world’s slimmest tractor (2 1/8" outside diameter; OD) was able to provide a pulling force of 3200 lbs and was powered by intervention fluid pumped through coiled tubing. The tractor has many failsafe features and self-cleaning mechanism of gripper arms to overcome the challenges encountered while tractoring in open hole. Four smart wells (with minimum restriction 2.81") were successfully matrix acid stimulated while the CT-Tractor combination were able to extend the reach of CT beyond lock-up depth. CT-Tractor was run-in-hole (RIH) to lock-up depth and then tractor was activated from that depth to extend the reach of CT. At total depth (TD), the tractor was isolated and de-activated by dropping steel ball. The wells were acid stimulated while pulling-out-of-hole (POH). Pre-flush was pumped while RIH at low pumping rate to avoid activating tractor before lock-up depth and after lock-up, pre-flush was pumped through tractor to activate the tractor. This paper outlines the tractor characteristics, matrix acid stimulation jobs design parameters, detailed operational data captured and the learning curve achieved during job execution.

This paper describes the extensive integrated engineering collaboration and optimization process to allow the operator to push the drilling and completion envelope to drill complex ultra extended reach drilling (ERD) wells in a mature field. The Wandoo field is located within WA-14L in the Carnarvon Basin, offshore Western Australia and is wholly owned and operated by Vermilion Oil & Gas Australia Pty Ltd (VOGA). Due to the shallow reservoir depth, extreme ERD profile and the high tortuosity requirement for the wells, significant challenges were identified during the planning stages of the campaign. To optimize well placement, update geological information and reduce collision risk with nearby producing wells, the Reservoir Mapping While Drilling (RMWD) service was run in real-time. The primary objective of the service was to place the well in the optimum position within the reservoir, this included (1) provide early detection of moved oil water contact (MOWC) while approaching well crossings with minimum separation factor to reduce collision risk and geological uncertainties; (2) to steer azimuthally to optimize the placement of the well with respect to the field bounding fault and reduce the drilling risk associated with the intersection of the fault; and (3) to distinguish between the A3 Upper (A3U), A3 Lower (A3L), and B sands to optimize well placement. These challenges were successfully overcome with extensive planning, integrated engineering designs, application of new state-of-the-art technology, good quality real-time data interpretation and a strong execution support from both rig site and town. As the result of good collaborative teamwork in planning and execution, the two highly technically challenging wells were drilled and completed successfully and brought online for production. A number of drilling performance highlights captured during the execution phase were identified as having significantly contributed to the successful completion of the project.

Drilling extended lateral sections to maximize reservoir exposure is key to optimizing field production and data recovery. However, it presents peculiar challenges not limited to hole-cleaning, wellbore stability, narrow drilling windows, and excessive torque and drag. Thus, customizing the fluid system to drill lateral sections requires information to understand the formation characteristics, including geomechanical data to determine the correct mud weight window, a precise selection of optimal fluid rheological properties, good inhibition, and lubricity, which are of foremost importance for extended-reach drilling (ERD) wells. The reservoir section of the well presented in this paper was previously drilled unsuccessfully twice, as the targeted zone was not reached. During the drilling phase, a large amount of non-productive time (NPT) was observed due to stuck pipe incidents, hole collapse, and then, hole cleaning issues were encountered while drilling. Another critical concern is the narrow mud weight window range, which causes the formation to break when Equivalent Circulating Density (ECD) increases beyond the pore pressure or fracture pressure of the formation. A new generation of High-Performance Non-Aqueous Based Mud (HPNBM) was engineered to drill these types of complicated, long horizontal intervals matching the drilling performance required to drill such sections and deliver a perfect gauge hole. This HPNBM provides high shear-thinning properties, an excellent low-end rheological profile, and rapid-set/easy break gels. This paper presents a successful well delivery of drilling the longest horizontal section in the country within a record amount of time. The previous attempts were carefully studied to identify the challenges associated during drilling and considered while designing this HPNBM. The high-performance non-aqueous based mud system proposed with stress caging technique was successful, economic, and drilled successfully with zero non-productive time (NPT) related to drilling fluids. Engineering software was utilized as hole cleaning is critical for drilling the horizontal sections to reach the targeted depth and run casing to the bottom. This paper presents the longest horizontal section (4,200 ft) to be drilled to the targeted depth as planned in Turkey. A comprehensive analysis that includes the planning phase, application, techniques, and performance of the mud system will be presented.

Achieving complete and efficient gravel packing is the primary objective when tasked to install an effective sand control completion. This paper describes the challenges faced during the selection, design, planning and execution phases of the open-hole horizontal gravel pack completions in the "L" field, offshore Republic of Congo. The open hole gravel packs (OHGPs) targeted the most prolific sand to ensure production objectives were achieved with the benefit of a gravel-pack completion. The operator completed two OHGPs with alpha/beta technique for the sand face completion utilizing concentric annular pack screen (CAPS), wire-wrap screens, and a service tool permitting post-gravel pack filter cake clean-up treatments. The accurate selection, modeling, and evaluation of sand control techniques were crucial for completion and production optimization, as well as risk minimization. The service approach had traditionally leveraged upon industry rules of thumb and previous experience, but as the reservoir section length increased and completion configuration became more complex, the error margins tightened and the cost of failure increased such that a more robust design approach was needed. This paper addresses several key factors that must be considered carefully when installing a successful gravel pack completion. The dynamic pressure management becomes critical to maintain the bottom hole pressures within a required range for the successful implementation of the gravel pack. Other factors include designing an optimal screen-wash pipe annulus ratio during alpha-beta wave packing, an optimal alpha wave height, and the use of multiple beta wave packing rates. Results from the preliminary modelling of the gravel pack pumping provided an accurate estimation of the maximum and minimum anticipated pumping rates and pressures. These parameter estimates were generated for the workstring design scenarios and provided guidance for the planned pumping rate adjustment during the gravel packing execution phases. The gravel packed wells achieved pack efficiency greater than 100% based on an estimated 8.5-in. diameter OH. Post completion multi-rate tests concluded potential productivity exceeding the operator's expectations. This paper describes the lessons learned and best practices developed for offshore Congo open-hole gravels packs, which have a very challenging well completion and reservoir scenario. Several proven completion practices are reviewed, with a critical examination of the application of these scenarios for future completion operations in this difficult operating environment. This applied methodology has made significant impact on future field development and increased the production expectations for the asset.

Plug and Perf (PnP) completions have been the most widely used multistage hydraulic fracturing methods in unconventional wells. In a PnP completion, isolation between stages is achieved by setting frac plugs inside the horizontal liner. The number of perforation clusters and perforation holes are designed using limited entry perforating techniques. While PnP is a proven method, there are also some downsides, particularly when considering the inability to pump plugs due to changes in casing integrity and casing deformation occurring in 20-30% of horizontal wells. Casing damage has been increasingly recognized as a challenge to well integrity in active or child wells during multistage hydraulic fracturing. Casing deformation and reduction in casing inside diameter (ID) prevent the use of PnP operations due to frac plugs being unable to pass through deformed casing. Cemented multi-entry ball-activated fracturing sleeves (ME-BAFS) allow users to imitate the limited entry effect of PnP completions while eliminating the need to deploy large OD frac plugs for each stage. The multiple entry points are activated using various-sized frac balls dropped from the surface as the stimulation treatment is pumped, eliminating the need to rig up and rig down between stages. After fracturing is complete, the frac balls either dissolve or are flowed to surface allowing production to begin immediately eliminating through-tubing intervention. The multi-entry ball-activated fracturing sleeves use graduated balls and ball seats to open as many as five sleeves per stage with a single frac ball for increased efficiency. Number of clusters and entry points are calculated based on limited entry techniques similar to PnP. Within this study, two limited entry techniques, PnP and multi-entry sleeve systems, are evaluated using commercial fracture modeling software, and well production modeling to compare the steady-state production between PnP and multi-entry ball-activated fracturing sleeves. Hydraulic fracture modeling is also used to evaluate limited entry perforation design, perf erosion, stress shadowing, and fracture propagation.

The Greater Enfield Project (GEP) is a challenging offshore oil development, designed to produce from the Laverda Canyon, Cimatti and Norton over Laverda oil fields. Six water injection wells are required to provide pressure support and sweep oil to three production wells in the Laverda Canyon and Cimatti oil accumulations to improve oil recovery. The GEP injection wells are a critical aspect of water flood design in a complex field, new to Woodside and with limited global benchmarks. A specific drilling and completion fluid system (Reservoir drilling fluid, completion fluid and chemical filter cake breaker) combined with a unique clean up and displacement technique have been adopted to provide high and sustainable matrix injection performance. While filter cake breakers have been previously used in the industry, they are typically combined with a flowback for filter cake removals. Filter cake clean up by means of flowback was discounted for GEP due to cost and the inability of some wells to naturally flow during early life. All GEP injection wells were completed in 2018-2019, one of which is globally the longest horizontal water injection well completed to date based on the Rushmore data base. Fieldwide injection commenced in July 2019 with favorable results. This paper summarises the key design aspects adopted to deliver successful matrix injection performance, presents the improvements implemented during offshore execution and provides an insight into the early life injection performance.

The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and there were some reservoir/wellbore coupled thermal models presented by researchers. Although current theoretical models are developed for some certain application scenarios, the industry have realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model. In this paper, we started with the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, and revised it to consider the special feature of openhole packer completion scenario. Since the formation fluid firstly flows through the fracture into the open-hole annular space between formation and the packer liner, then flow along the annular space until meet the frac port on the production pipe, we add a simulation sub-region representing open-hole annular which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-fold flow regime caused by the simultaneous flow and heat transmission in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to Joule-Thompson cooling effects at the fracture and frac port locations if they are not consistent. With the improved mathematical model, DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in Erdos Basin of China was simulated and analyzed. The improved model with open-hole packer completion was applied and then the gas rate prediction was accomplished.

The emergence of Real-Time Well Construction Performance Monitoring Centers has significantly improved the service delivery for Operators across numerous offshore oil fields in Australia. New technologies and workflows were implemented for 3 Australian offshore wells, with the primary objective being to improve drilling efficiency while managing the associated risks. Additional objectives included optimizing daily operational performance, thus delivering time savings for the Operator and highlighting areas of possible improvements. The workflows combined proven technologies, software and wellbore surveillance services, which delivered risk-free wells ahead of Authority for Expenditure (AFE), by targeting the reduction of nonproductive time (NPT) and invisible lost time (ILT), together with risk management. The workflow began with a preliminary field analysis to identify the main challenges and areas that needed improvement. The key learnings were then consolidated on a comprehensive drilling road map by well section that outlined prevention and mitigation measures, expected rate of penetration (ROP) and recommended drilling parameters. The study also identified performance benchmarks such as average and on bottom ROP and connection time. Key performance indicators (KPI) were developed to monitor progress and track the well with respect to well improvements versus the benchmarks identified. The selection of the monitoring tools and modules required during the Execution Stage were developed based on the risks and KPIs identified during the field study and were further tailored to target specific challenges such as stuck pipe prevention, hole cleaning, shock and vibration and connection time. The workflows enabled the flawless execution of 3 offshore wells 29.0 days ahead of AFE which saved the Operator USD 15.5M. The closed loop monitoring enabled real time interventions which aided in preventing risks such as stuck pipe, ensured efficient shoe-to-shoe drilling and avoided potential lost-in-hole (LIH) costs. This case study demonstrates the use of a novel approach to increase well construction efficiency by eliminating lost time while enhancing risk control. The main basis for success of this workflow was using existing and cost-effective technologies while capitalizing on the renewed synergy between different departments such as Drilling, Mudlogging and Well Operations analysis. The workflow was and can be customized based on different needs, by combining specific modules for monitoring, analysis and wellbore surveillance services, to increase the efficiency of any well construction.

Historically, stuck-pipe events have been shown to cost the industry several hundred millions of dollars per year, and over 30% non-productive time ( Muqeem et al. 2012 ). In all cases, remedial operations to salvage the subject well are expensive; and success is not guaranteed. This paper describes a case history demonstrating how a differentially stuck string was freed in a relatively short time using an innovative enzyme/weak acid recipe. The string was a 4-1/2 in. lower completions bottom hole assembly (BHA) comprising of swell packers, and inflow control devices. The string was deployed in a carbonate reservoir. After deploying the string in the first 1,000 ft of open hole, the crew stopped to fill up the string to confirm circulation. Upon resumption of operations, the completions string was found to be stuck with no string movement possible in the upward or downward direction. Full circulation was still achieved. The fluid in hole was a water-based fluid. The string was diagnosed to be differentially stuck. It was established that the stuck point was across the high permeable zone. Efforts to work the string free with glycol pills proved unsuccessful. An attempt to place 20%; HCl acid induced up to 30 - 40 barrels per hour (BPH) dynamic losses at the shoe. Luckily, the losses healed relatively quickly, but the string remained stuck. After 29 hours of several unsuccessful attempts, a recipe of an enhanced combination pill of enzymes, and a weak acid accelerator was proposed, pumped across the stuck point, and allowed to soak. After a relatively shorter period of soaking, the string became free. The action of the enzyme/acid pill worked by destroying the polymer base of the filter cake created by the water-based drilling fluid. The homogeneous placement and action of the enzyme/weak acid pill across the stuck area ensured that it was more effective than the conventional HCL acid pill. Hence, the application is being presented as a potentially safe, efficient, and cost-effective option to free a differentially stuck BHA in water-based drilling fluid. Success in freeing a stuck-pipe usually depends on two critical factors - an accurate diagnosis of the mode of stuck-pipe event (i.e. differentially or mechanically); and the ability to implement the remedial operations quickly, and effectively. By implementing the above described technique, significant non- productive time (NPT) was averted. The technique has since been implemented in subsequent differential stuck-pipe events in water-based drilling fluids with a 100%; success rate.

The recent, sustained depression in global oil prices has driven a significant reduction in upstream Exploration and Production (EandP) expenditure, particularly in the capital-intensive offshore environment. The high costs traditionally associated with EandP development projects, specifically in subsea developments, have driven a requirement for the adoption of technologies that not only increase the efficiency of the well construction process, but also reduce the total number of wells required, whilst increasing production rates and recoverable reserves. Building on recent industry experiences with the varying multilateral systems available, Woodside implemented the use of an alternative innovative multi-lateral system, which has gone through multiple evolutions and marked improvements in system reliability and installation efficiency compared to Woodside's previous multilateral experience. The latest evolution of this system has been implemented during the construction of multi-lateral wells for the Greater Enfield Project (GEP). Within GEP, the Norton over Laverda (NoL) field development comprises three tri-lateral production wells (namely NoL01, NoL02 and NoL03). Norton field is an offset to the Vincent field, which employed an alternative multi-lateral completion design. On average, the Norton multi-lateral well operations were executed 15-30% faster than previous comparable Woodside installations. This has been attributed to the application of operational learnings from the previous Vincent multi-lateral development and the implementation of the new system. These wells were constructed in water depths of > 800 m, the deepest for such a system globally. Of the three wells, NoL01 and NoL02 were constructed well under budget, and ahead of schedule. NoL02 was constructed in a time that benchmarked as the fastest well per 1,000 m versus basin offsets. NoL03 was completed within budget, whilst having faced two major NPT (Non-Productive Time) events (ultimately resolved using world first solutions for the given system). This paper will discuss the successes, challenges experienced, and lessons learned during the installation of the three Norton tri-laterals. This field is a prime example of how new technology and the installation practices for multilateral systems within the operator's assets of the North-West margin of Australia have improved over time.

Water-oil emulsion formation is commonly observed at wellhead chokes and topsides control valves, with the impact mitigated by chemical injection. The presence of emulsions downhole in Pyrenees wells was inferred from their significant production rate impact and confirmed by the uplift observed from downhole chemical injection. The Pyrenees fields are located in the Exmouth sub-basin offshore Western Australia. Through analogy between individual Inflow Control Device (ICD) orifice elements and wellhead chokes, ICDs were suspected as the source. This paper describes experimental confirmation of emulsion formation by orifice type inflow control devices in Pyrenees field horizontal well completions and proceeds to characterise the emulsions formed. A purpose built flow rig combined Pyrenees crude oil and produced water under low shear, simulating reservoir flow conditions, before flowing through an orifice element at rates equal to peak and mid-life production. With liquid flow rate held constant, water cut was increased in 10% steps from 0 to 100% water content. A key component of the experimental system is a benchtop Nuclear Magnetic Resonance spectrometer equipped for non-invasive Pulsed Field Gradient measurement of the Droplet Size Distribution of the emulsions formed. Droplet size distribution is a fundamental fluid property that significantly impacts emulsion rheology. The heavy end component of the crude oil was characterised by a novel Enhanced Saturate Aromatic Resin and Asphaltene analysis procedure to facilitate benchmarking of Pyrenees with emulsion formation tendencies of other producing assets. This quantitative demonstration of emulsion formation by orifice type ICDs at near reservoir conditions is novel, as is observation of partial emulsification, and represents initial steps towards generalisation of models for emulsion formation and their transport properties.

To control and equalize the horizontal well drawdown, Autonomous Inflow Control Device (AICD) are planned to be installed along the homogenous reservoirs in five infill wells at B field, Sarawak offshore (Malaysia). The very low viscosity contrast between oil and water (0.6cp and 0.5cp) with 37API degree at B gives unfavorable mobility ratio and water flows with a higher velocity than the oil. This paper presents the interdisciplinary approach to completion design needs which evaluated the efficiency and performance between conventional completions compared with passive inflow control device (ICD), AICD namely Rate Control Production (RCP) and Fluidic Diode to qualify the representative technologies for use at B fields. The very purpose of this flow control device is the extension of well life due to deferment of water and/or gas production prior to water and/or gas breakthrough occurs. Flow performance tests are used to measure the performance of these various flow control devices at representative downhole conditions. The comparative analysis was primarily based on elapsed time comparisons for water/oil ratio (WOR), gas/oil ratio and water cut and sensitivity to historical drawdown, productivity index and production cumulative performance. To reduce formation damage and screen plugging effect in these horizontal section, appropriate fluid conditioning, fluid displacement, filter cake breaker system and compatibility between screen and the fluid in which the bottom hole assembly (BHA) will be deployed are discussed in this paper. The gas-water-control completion using AICD technology is predicted to provide significant benefit during the field development with incremental oil recovery around 10-40%, allowing well production with low water and gas production.

Eromanga Basin in central Australia was deposited from early Jurassic to late Cretaceous and has witnessed commercial discoveries in different formation units throughout the basin's spatial distribution. Lately, operators have shifted from vertical to horizontal wells to enhance production outcomes. However, there are still many challenges for achieving and enhancing these benefits with horizontal drilling. These include navigating an undulating reservoir structure whilst staying in the target zone and maintaining appropriate vertical standoff from oil water contact (OWC) to avoid early water breakthrough. In this paper, the author summarizes the experiences and approaches made in tackling and resolving these challenges, by elaborating on the new methods applied during the recent horizontal drilling campaign. These include new drilling technologies, such as the latest rotary steerable systems and new logging-while-drilling technologies, such as the multilayer bed boundary detection services. The methodology of using this data both while-drilling and post-drilling for critical decision making on both geosteering and completion strategies, is also addressed. The author illustrates an integrated approach that was adopted by incorporating new data into the reservoir model for the purpose of referencing and planning future wells. Case studies from two of the recent wells are discussed in detail to illustrate the operational workflows and the integrated approach. Landing and geosteering practices are examined separately to demonstrate how to achieve best results and avoid both identified and potential pitfalls. The overall drilling and production performance of the recent ten wells are summarized, as are the results of applying these methods. Finally, the author reveals the new insights that the post-job data integration brought for the field. This new approach has allowed the operator to drill an increased number of wells than originally planned in the same timeframe. This approach has also allowed for longer wells to be drilled. By comparing the production benefits with the cost of drilling, the author shows the viability of these methods in resolving the challenges of horizontal drilling in this region.

Staged hydraulic fracturing in horizontal wells is one of the most popular techniques in developing conventional and unconventional reservoirs, where multiple fractures initiate and propagate simultaneously and then interact with each other. It is shown in hydraulic fracturing practices that these interactions lead to unsatisfactory production performance in many fractures. It is of great importance to develop a reliable hydraulic fracturing simulator that can completely effectively take these interactions into account and predict fracture behavior accurately. We develop a fully coupled 3D hydraulic fracturing simulator with the finite element method, where the interaction between fractures is completely taken into account. We develop a finite element equation to describe fracturing deformation and propagation based on linear elastic fracture mechanics, another one to describe fluid flow and leak-off within fractures, and friction equations to describe the effects of the perforations and tortuosity. We solve these three equations in a fully coupled and implicit way, and obtain fluid pressure, fracture width, and injection allocations between fractures in every step simultaneously. Followed by the method’s verification with experiments, we simulated staged hydraulic fracturing with the coupled finite element simulator and investigated the interactions’ effects. It was found in the simulation that the perforations have the ability to make the injection allocated very even. However, fractures propagate and evolve in very different manners due to the interaction between fractures. Some fractures are far longer than others, while their fracture widths close to the wellbore are far smaller. Due to the stress shadows arising from the fracture interactions, some wellbore zones in the longer fractures never break, and in these fractures their widths around the tip zones are larger than those around the wellbore zones. Insights from the simulations are helpful to understand the mechanisms leading to the unsatisfactory production performance of the fractures, and the simulator can therefore be used to optimize staged hydraulic fracturing.

Drilling into carbonate reservoirs presents challenges involving damaging vibrations to drilling assembly components, encountering total drilling fluid losses, formation damage, potential loss of directional control if drilling into karst structures, and formation evaluation, particularly with high reservoir uncertainty. These challenges are exacerbated by the need to drill a long, relatively smooth 6,000-ft horizontal ERD well for autonomous inflow control device (AICD) smart well completion at 45 ft TVDss below the GOC. This paper describes collaborative efforts amongst different facets of drilling, fluids, and drill bits with the operator drilling team. Planning, risk assessment, directional drilling, and formation evaluation solutions are discussed for total drilling performance from spud to well TD for three wells in Phase 1 of this campaign. The elongated narrow nature of the carbonate pinnacles and optimal oil ultimate recovery dictates horizontal production hole placement in the mid-point of the thin oil rim. Well designs were optimized with consideration for anticollision risk, optimum reservoir recovery, karst avoidance, shallow hazard, extended reach drilling the long horizontal section with minimal undulation, in-field referencing (IFR) surveys to minimize well bore uncertainty, fluid management for optimum hole cleaning, and drill bit designed for penetration rate and minimal vibration. BHAs were modeled for directional control, drilling efficiency and damaging vibrations from drill-bit and BHA components. BHA simulation incorporating downhole vibration isolation tool mitigates and decouples damaging vibrations. The high fluctuation of 5 to 40 kpsi compressive strength from offset Carbonate sections induces vibration damage to drill-bit cutters if not designed out. Fluids design focused on drilling using a waterbased mud and readiness to combat severe or total losses. Fluids design for the horizontal section requires both an easy to clean filter-cake if switched to Pressurize Mud Cap Drilling (PMCD), and on acid-degradability of the filter-cake if drilled using conventional drilling allowing the application of an in-situ acid generator filter-cake breaker system, optimized fluid performance for hole cleaning, pressure management, and torque and drag reduction by means of nondamaging lubricants. The ultradeep-resistivity inversion successfully mapped and reduced seismic uncertainties and achieved optimal well placement within the thin oil rim. The rigorous planning and risk mitigations paid dividends. All three wells were flawlessly drilled with one run BHA in each hole sections, no karst losses necessitating PMCD, and delivery within a 10-ft TVDss window for the 6,000-ft horizontal sections. Drilling rate of penetration was 50% faster compared to offset benchmarking, setting new best in class performance for the Sarawak carbonate field. Particle size distribution in the drill- in fluid was kept within a narrow range to maximize bridging and reduce fines invasion. The combination of a nondamaging fluid and in situ acid precursor rendered predicted hydrocarbon production above expected productivity of the well.

Successful reservoir surveillance is a key component to effectively manage any field production strategy. For open hole extended reach horizontal wells, including some wells over 30,000 ft in length, the challenges to successfully deploy real-time logging tools are greatly magnified. This is further complicated by constraints in the completion where Electrical Submersible Pumps (ESP's) are installed. A comparative review of the latest technologies and methods available to overcome these challenges will be explored. The challenges are formidable and extensive; logging these extreme lengths in cased hole would be difficult enough, but are considerably exaggerated in the open-hole condition. The logging run in open hole must also contend with increased frictional forces, high dogleg severity, washouts and an increased well bore rugosity. The main challenges to achieve the logging objectives in open hole extended reach wells, are 2-fold, namely; To log the entire open hole section and reach the Total Depth (TD) of the well. To obtain high quality data from the logging tools, despite the adverse downhole environment. To achieve these 2 main objectives, a comprehensive approach is taken while designing the logging operation. The choices available to deploy the logging tools are mainly on electric-line cable with an electric powered tractor or on coil tubing with a hydraulically powered tractor. The most common type of log performed in these extended reach wells is a production log to measure multi-phase inflow contributions. To improve the success rate of the logs, a number of initiatives have been implemented, including deployment of custom designed coil tubing tractors and state of the art wireline tractors. The logging tools and job programs are adapted based on the results of simulations, accounting for many variables, including the completion, well type, deviation and target depth. The ability to successfully log these extended reach wells cannot be understated, reservoir simulations and management decisions can only as good as the quality of data available. Some of the advantages of drilling mega reach wells such as increased reservoir contact, reduced footprint and less wells drilled will be lost if adequate reservoir surveillance cannot be achieved. To meet the key objectives, creative solutions including designing and upgrading the best fit for purpose technologies are applied for the extended reach wells. These steps taken not only improve the overall logging performance, they can also result in cost savings by avoiding multiple unsuccessful logging runs.

An operator and a service company parternered in successfully drilling the longest extended-reach drilling (ERD) wells in the Sultanate of Oman. The project consisted of four wells to be drilled in the G field. These wells will be the first aquifer pumpoff wells drilled in the field with a goal of lowering the reservoir water cut (oil/water contact) for all nearby oil producers, and to minimize water production and maximize oil production. The buildup section required drilling through the risky gas cap and zones having possible total fluid losses. The risk of stuck pipe and the likelihood of gas kick, as well drilling through fractures on the horizontal section and experiencing potential total fluid losses, made successfully drilling the wells to TD even more difficult and challenging. The buildup section was divided into two string designs based on a previously used single-string design. The drilling objectives were to reduce and separate the risks in the different sections and to drill the gas cap formation in the 12.25-in. shale section, plus landing the well with possible fluid losses while entering the reservoir with the 8.5-in. bottomhole assembly (BHA). This drilling plan eliminated known risks, using BHAs for drilling the 12.25-in. section with a push-the-bit system, and drilling the 8.5-in. section with a high-buildup rate rotary steerable system (RSS) for dogleg severity assurance. Drilling both sections was performed with a near-bit gamma ray adapter for geostopping. The 6-in. lateral section was the main challenge in the drilling operations due to the anticipated highly fractured reservoir with possible total fluid losses and high-equivalent circulating density management. Poor borehole cleaning was expected due to the high-critical transport rate, as well severe shock and vibrations. The BHA was designed to be able to drill to TD using the following techniques: A finite element analysis (FEA) model was developed to determine the most excellent drillpipe to be used in terms of shock and vibration and buckling moments. The model recommended 4-in. drillpipe to reduce the high-surface pressure expected at TD. The FEA model helped in selecting the best driving system (motorized BHA) because the simulations indicated that the BHA would have lower shock and vibration and be able to handle the expected high-surface torque. Due to the expected faults and possible sidetrack, the final BHA selection was a motorized high-buildup rate RSS. The real-time parameter management and plan helped in selecting the best drilling parameters to minimize real-time shocks and vibrations. Drilling the buildup section with the two-casing string design solved the risk reduction and allowed for landing the four wells successfully. For the lateral section, the BHA design met the expectation of completing the drilling operation on one run to TD. Both companies teamed to successfully drill the two longest ERD wells in the Sultanate of Oman. All of the wells are in the very extended-reach group by ERD definition. Well G-55 is the longest ERD ratio well drilled to date by the operator with a 4.01 ratio.

Horizontal well type was selected to optimize drainage of a mature field which had less than 3 years prior concession end. However, the well construction of horizontal well is relatively more challenging compare to other well type which will lead to higher cost. Offset well execution data showing that the challenges of drilling this well type were wellbore instability, drill bit worn out due to gravel zone, uncertainty on marker prognosis and the potential differential sticking on lateral section (inside the depleted reservoir) especially during running pre-perforated liner as completion equipment. It was realized that drilling performance improvement is required to reduce the cost and accelerate the production. To overcome the challenges, several technologies were introduced. Drilling fluid optimally designed to support borehole stability and real-time adjustment were performed by analyzing the drill cutting. Ridged shape cutter bit utilized to aid during penetrating the gravel zone. To maximize the penetration rate, point-the-bit Rotary Steerable System was utilized for better weight transfer and improved wellbore geometry compare to conventional mud motor system. To manage uncertainty of marker prognosis, the Bottom Hole Assembly (BHA) was designed to achieve maximum dog leg severity capability by minimizing the number of stabilizers. Near bit gamma ray sensor also installed to aid timely formation marker identification. To mitigate risk of differential sticking, the bridging agent sized to fit with the formation permeability through particle size distribution analysis. Centralizers also installed on pre-perforated liner assembly to minimize contact area which might cause differential sticking. Though these technologies application has been used on many occasions, they were new to this field development which raised concern over their potential risk, especially with limited investment period. Therefore, a series of execution assurance processes were performed. Cross-functional risk assessment sessions were held to review trade-offs of each new technology potential value with the potential cost incurred by considering the possibility of success and potential changes on other aspect of the well construction that need to be adjusted to accommodate the application and mitigate its potential risk. Then a drill-well-on-paper session held with all personnel that would involve by simulating the drilling execution following the procedure which then improved by creating mitigation steps or provide clarity. Artificial intelligence assisted decision support center was also utilized to monitor execution and aid performance improvement recommendation utilizing geomechanics, hydraulic, torque and drag model as well as the field best practices. These all result to 17% cycle time improvement with 9% lower cost compare to typical well. The production sweet-spot zone exposure also increased by 20%.

In this paper we present a new data-driven methodology for a drilling bit position and direction determination. The model is based on machine learning approach and trained on a data collected in a real-time or near real-time: mechanical parameters of drilling, tool-face data, MWD/LWD data, etc. The proposed methodology might be an interest for directional drilling service companies, operator companies that develop low-thickness productive strata. One of the main advantages of the proposed approach is economic efficiency which it provides due to absence of additional costs associated with payments for additional man hours for precise trajectory and direction monitoring. Methodology allows to predict trajectory at any time of drilling. The methodology is illustrated on the historical data of drilling of one oilfield. At the current stage, the results of the testing show good quality. Blind test on 154 independent sliding episodes shows that median absolute error (MedAE) of depth, inclination and azimuth are 0.26 m, 0.25° and 0.42°. These errors will decrease after adding more wells and steps, which are described in future plans.

Refracturing of existing producing wells is an economical option for increasing production when compared to new drills ( Urban et al., 2016 ; French et al., 2014 ). However, stage isolation during refracturing of horizontal wells can be a challenge, especially in open-hole horizontal wells. Segmentation with common mechanical tools is of high risk and costly, even ineffective sometimes. This paper presents a new tool-free refracturing technology for open-hole horizontal wells in tight oil reservoir employing chemical diverting agents and real time microseismic monitoring technology. The implementation procedures are as follows: First, reservoir characteristics, surplus oil distribution and brittleness index are evaluated to identify the best perforation candidates for creating new fractures. Second, through the classification of predicted breakdown pressures, number of temporary plugging and diverting fracturing stages are determined. The dosage of granular and powdery plugging agents is designed. Finally, refracturing treatment are performed with an injection procedure of ‘granular plugging agents+ fracturing fluid + proppants+ powdery plugging agents + fracturing fluid’, and microseismic monitoring technology is used to help judge the effect of refracturing and adjust the refracturing operations in real time. The refracturing treatment was performed in Well X located at Junggar Basin in western China using the method presented in this paper. The microseismic monitoring results show that multi-stage new fractures perpendicular to the horizontal well were created and a more complex fracture network was generated by refracturing in the reservoir, which verifies the validity of the tool-free refracturing of open-hole horizontal wells with chemical diversion agents. After refracturing operation, daily oil production of Well X remarkably increased from 5.1 t/d to 25.1 t/d (one year after refracturing) in the field test. This study provides an effective tool-free refracturing technology for open-hole horizontal wells, and it was firstly applied in China. It also provides guidelines to the working engineers with respect to refracturing stimulation design and commercial viability. In addition, this technology is not only suitable for open-hole horizontal wells, but also for casing-completion horizontal wells.