The Mishrif formation in west Kuwait is a tight carbonate reservoir having low oil mobility. It is fractured and heterogeneous with wide variation in porosity ranging from 10 to 25%, matrix permeability of about 0.1 to 10 md, and 20°API oil. Production tests and geomechanical study results have revealed that productivity is mostly from the high-permeability matrix and critically stressed fracture networks. Recently, the Mishrif development has been dominated by horizontal wells to maximize reservoir contact and enhance productivity. However, a challenge in such openhole completion is the stimulation strategy requiring effective diversion technology due to the uneven acid distribution along the lateral section. To address those challenges, a novel engineered workflow has been implemented relying on distributed temperature sensing (DTS) to assess the fluid coverage across the openhole section. Results enable identifying high- and low-intake zones, segmenting the uncased section into intervals requiring different levels of stimulation, and making informed decisions regarding diversion requirements. The intervention was conducted in two stages. Coiled tubing (CT) was the selected fluid conveyance method on the first stage given its capacity for more controlled fluid placement, and high-rate bullheading stimulation was selected for the second stage. During the treatment, multiple challenges were faced, mainly driven by a high-permeability streak identified by the DTS near the heel of the lateral. The CT stimulation procedures were modified on the spot, and measures were taken to minimize the impact on the thief zone, which included a combination of diversion techniques, such as high-pressure jetting, dual injection, and pumping of a near-wellbore nonreactive diverter, which is composed of a customized blend of multimodal particles and degradable fibers to minimize fluid leakoff into the high-intake zone. Likewise, real-time downhole telemetry was crucial throughout the CT stimulation because it allowed the highest injection rate possible below the preset pressure limits, continuous monitoring of downhole dynamics along the intervention, and optimal actuation of the high-pressure jetting tool. Upon completion of the CT stimulation, a second DTS log was carried out to evaluate the fluid coverage and effectiveness of the diversion strategy, enabling further adjustment of the bullhead stimulation program. This stimulation workflow implemented in west Kuwait represents a cost-effective alternative to stimulate openhole tight carbonates. This study brings new perspectives for treating complex reservoirs in the region, and shares lessons learned for future interventions.

Effective fracturing of horizontal wells is the key to successfully producing unconventional reservoirs. Correct evaluation of existing created fractures is essential for identification of key treatment variables in the target reservoir and continuous process improvement of the total process. Measurement and analysis of Frac-driven Interactions (FDI) has become a popular technique for rapid and cost-effective evaluation of existing and new fractures created in horizontal wells for production of unconventional reservoirs. Specific parameters used for their evaluation include detection of the start and end time of FDI during each frac stage, its magnitude, and duration. Another important parameter is observing smoothness of FDI variations with time. The paper offers specific recommendations for additional measurement and computational steps that can be used for determination of the volume and rate of fluid migration causing the observed FDI.

One of the responsibilities of a directional driller (DD) is the computation of the current bit position given the last survey station measurement, and with that information calculate the path back to plan if directional correction is needed. Having only a few minutes during a drilling connection to perform these calculations, the DD is limited to compute only a handful of possible paths that will be presented to the Drilling Engineer/Company Man. With this information, the Company Man will decide which path to follow. The present work aims to develop a computer algorithm that replicates the field knowledge of DDs but can compute hundreds of paths in less than one minute. In addition, since the objective of the trajectory correction may differ, the algorithm also can optimize for one of three goals: maximum rate of penetration (ROP), minimum tortuosity in the path, or maximum footage in the drilling target window. The paper presents examples of four different path recommendations in the lateral portion of a horizontal well. The results show the optimum recommended paths for the same position for a specific optimization goal. Finally, a comparison between the running time and number of paths computed is presented. All results were obtained during the validation tests of the algorithm.

This paper develops a mathematical model for rate transient analysis in multi-stage fractured horizontal wells with considering weak fluid supply. A new concept of additional skin factor is introduced in the proposed model to characterize the fluid supply. Then, the mathematical model are solved by using the perturbation transformation, point source integration method, Laplace transform, and numerical inversion, while the fracture flow equations are solved by fracture discretization and superposition principle. First, the flow regimes of multi-stage fractured horizontal wells with considering weak fluid supply are identified based on the rate transient behaviors, including wellbore storage and skin effect, bilinear flow, linear flow, pseudo-radial flow in the fractured zone, interface skin effect, pseudo-radial flow in the original zone, and boundary-dominated flow. The effect of additional interface skin makes the double logarithmic curve of production rate appear an abrupt "overlap". The results of the sensitivity study show that the abrupt "overlap" becomes more obvious with the increase of the fracture conductivity, fracture number, the stress sensitivity coefficient, especially the interface skin. Finally, the proposed mathematical model is used to perform a case study on the production data of actual tight-gas wells from the Ordos Basin. The interface skin factor, fracture half-length, fracture conductivity, and boundary radius are evaluated. Through the proposed model, the characteristics of weak fluid supply in tight gas reservoirs are fully understood.

In unconventional reservoirs, optimal completion controls are essential to improving well productivity and reducing costs. In this article, we propose a statistical model to investigate associations between shale oil production and completion parameters (e.g., completion lateral length, total proppant, number of hydraulic fracturing stages), while accounting for the influence of spatially heterogeneous geological conditions on hydrocarbon production. We develop a non-parametric regression method that combines a generalized additive model with a fused LASSO regularization for geological homogeneity pursuit. We present an alternating augmented Lagrangian method for model parameter estimations. The novelty and advantages of our method over the published ones are a) it can control or remove the heterogeneous non-completion effects; 2) it can account for and analyze the interactions among the completion parameters. We apply our method to the analysis of a real case from a Permian Basin US onshore field and show how our model can account for the interaction between the completion parameters. Our results provide key findings on how completion parameters affect oil production in that can lead to optimal well completion designs.

Tortuosity is one of the critical factors to be considered for complex directional well trajectories, complicated build rates, precise steering in thin reservoirs, and extended reach wells. This paper discusses the pitfalls of estimating tortuosity to quantify borehole quality and answers questions, such as whether the claimed benefits (i.e., enhanced drilling performance, improved hole cleaning, ease of running casing, and superior cement operations) can be fully attributed to reduced borehole tortuosity. Running casing may mask the tortuosity present in the as drilled open hole wellbore section. This vanishing tortuosity alters the apparent "wellbore quality" and the new tortuosity representative of the cased hole path may present new appearing tortuosity. Both vanishing and appearing tortuosity are generally neglected in engineering calculations. Conventional methods to calculate tortuosity are based on the predetermined shape of the trajectory using the minimum curvature method. Wellbore undulation (geometrical tortuosity) is determined using geometrical measurements such as inclination, azimuth, and calculated displacement; however, much of this wellbore undulation vanishes after the casing is run, and thus the cased off wellpath appears smoother. This apparent change in wellbore tortuosity results from the flexural stiffness and rigidity of the casing pipes, and the compression and tension loads along the length of the casing string. Acquiring a subsequent survey along the cased well path yields new inclinations, azimuths, and displacements. This new survey records wellpath undulations resulting from the casings path through the original open hole wellbore geometry and what we call tubular undulation (mechanical tortuosity) which is specific to the path and position of the casing within the wellbore. The smoothing of the wellpath resulting from the casing masking original wellbore tortuosity results in the original geometrical tortuosity vanishing while the new undulations resulting from the mechanical tortuosity of the casing causes additional tortuosity to appear. The comparison between the geometrical and mechanical tortuosity provides a method of quantifying the vanishing and appearing tortuosity.

With the expanding offshore rig activity in United Arab Emirates leading to an increased number of horizontal wells and longer drains, coupled with changing rock fabrics, it became imperative to diverge from the existing stimulation methods to deliver more consistent and reliable results. These results were achieved via the introduction of single-phase retarded acid (SPRA) and viscoelastic diverting acid (VEDA) to both active and shut-in wells offshore. The introduction of SPRA and VEDA was possible after extensive laboratory testing including core flow tests, solubility tests, emulsion tendency testing, and corrosion inhibition tests to evaluate and benchmark the performance of these blends in comparison to the existing acid recipes such as plain HCl and polymer-based diverted acid. These tests showed that a combination of SPRA and VEDA would allow maximizing lateral coverage and enhance acid penetration due to the reduced rate of reaction and chemical diversion capabilities from thief zones. Combining the introduction of SPRA and VEDA with a shift to bullheading and higher pumping rates enabled the delivery of previously unachievable production results at sustainable wellhead pressures or even well revival of shut-in wells. In addition, reduction of acid content for dolomite stimulation was possible due to the implementation of acid retardation, which also allowed protecting wellheads from exposure to higher acid concentrations while bullheading. Treatment parameters such as volumes, rates, and acid/diverter sequence and ratio were then adjusted for optimal wormhole penetration across all zones using a new carbonate matrix acidizing modeling software. Post-treatment evaluation for the cases of previously shut-in wells has proven the success of the SPRA and VEDA combination. Shut-in wells that were unable to produce sustainably at the required tubing-head pressure (production flowline pressure), were able to produce sustainably with a 100% increase in production compared to prestimulation testing. Similarly, for gas wells, the combination of SPRA and VEDA resulted in a 50% increase in production at a similar bottomhole pressure. In addition, water injectors have also exhibited sustainably increased levels of injectivity compared to prestimulation levels, leading to better sweepage. The novelty of this paper is the comparison between historical carbonate stimulation results in UAE using plain HCl acid with polymer-based diverted acid and using SPRA with VEDA. It also sheds light on the game-changing solutions that suit the ever-increasing challenges observed in offshore oil and gas wells including well placement, lithology, permeability contrast, and type of hydrocarbon within the various target sublayers.

The development of carbonate reservoirs of a giant field, Offshore Abu Dhabi, requires long horizontal wells to maximize productivity, but at the risk of unwanted gas and water channeling through its inherent heterogeneities. Conformance can be enhanced with dedicated segmented completions (blank sections, Inflow Control Device, Autonomous Inflow Control Device, etc.) or selective acid stimulation (diverter, Limited Entry Liner), which are increasingly implemented to extend well life, and eventually well value. If these technologies have matured, success depends heavily on the quality of the formation knowledge prior to completion. As of today, conventional logs provide the basic ground, but they lack dynamic information, whereas production logging results are obtained too late, when the well is already completed. Initially introduced for the optimization of unconventional well completions (see Jacques et al, URTEC 2019), the Well Testing Logging (WTLog) offers the advantage to record a log of mobility, at the end of drilling the openhole, enabling a favorable timing to influence adapted completion and stimulation design. Contrasted viscosity brines are sequentially circulated through the drill pipes at a constant rate and back-produced from the casing at constant pressure. The fluids interface travels in the drain from the TD to the casing shoe, and the measurement of the differential formation seepage is interpreted into an injectivity profile. Combined with rate fall-off phase analysis, permeability and skin logs are derived. Lasting a few hours and realized with conventional rig equipment (such as cement pumps, coriolis flowmeters, Managed Pressure Drilling system), it is a nonintrusive, safe, and ultimately low-cost operation. Forward, it can replace costly logging, when aimed at characterizing heterogeneities. Within a year, the two first WTLog pilots of the Middle East were successfully designed and carried out. They targeted two appraisal wells in distinct undeveloped reservoirs (Cretaceous and Upper Jurassic formations) which benefited from rich acquisition programs (Image log, Production log) to benchmark and qualify this technology. After an explanation of the technology principles, this paper describes the design, operations, and results of these pilots. It then focuses on the petrophysical consolidation of the matrix/fracture characterization. It concludes by sharing the learnings and offers insight to what extent it is a promising technology to be applied in Middle East carbonate reservoir developments.

Multilateral technology has for nearly three decades extended the production life of fields in the North Sea by delivering a higher recovery factor supported by the cumulative production of the multiple laterals. Additionally, operators continue to look at methods to reduce the environmental impact of drilling and intervention. Taking advantage of the latest multilateral technology can turn otherwise unviable reservoirs into economically sound targets by achieving a longer field life while minimizing construction costs, risk, and environmental impact. This paper will focus on mature fields in the region that have used multilateral applications for wells that were reaching the end of their life and have been extended to further economic production. This paper discusses challenges faced to provide a multilateral solution for drilling new lateral legs in existing wells where there is a lack of available slots to drill new wells. Additionally, discussion will cover completion designs that tie new laterals into existing production casing. The case study will include discussion of workover operations, isolation methods, and lateral creation systems. The paper focuses on the challenges, solutions, and successful case study of a retrofit multilateral well constructed in the North Sea which extended production life in a mature field by using innovative multilateral re-entry methods. The paper also provides insight as to methodology for continually improving reliability of multilateral installations to maximize efficiencies.

The post COVID-19 era will undoubtedly present paradigm shifts in operational planning and execution and advanced automation will become an important factor. However, drilling automation without directional drilling ( Cayeux 2020 ) capability will exclude the use of automation in a vast number of fields where precise placement of the wellbore has shifted from a luxury to a necessity. This is important in unconventional plays where automation can make a step change in operational outcomes ( Chmela 2020 ). However, most efforts in automating directional drilling are using bespoke rigs ( Slagmulder 2016 ) and bespoke bottom hole assembly (BHA) that limit operational options. The goal is in designing systems that enable directional drilling automation ( Chatar 2018 ) with existing BHAs. This paper will look at three challenges that were identified and overcome to deploy a vendor agnostic system for automating the directional drilling (DD) process. The three challenges identified here are as follows: Using any mud motor including low-cost motors in a closed loop Integration with an existing measurement and logging while drilling (MLWD) system Ability to roll out automation systems on any operations with existing rigs The system is a modification of an operator’s autonomous drilling system ( Rassenfoss 2011 ), designed to use existing rigs, BHAs and have minimum footprint on the rigs for operational use. The system will have a dedicated connection to the rig’s programmable logic controller (PLC) via common industrial protocols including Modbus, EthernetIP or Profinet, a physical connection the MLWD receiver and a brain box with a cloud connection to aggregate, process data and send commands to the rig PLC to execute directional commands. A vendor agnostic system will increase adoption of automated technologies and further drive improvements in operational and business performance.

Horizontal well development often increases field production and recovery due to increased reservoir contact, reduced drawdown in the reservoir, and a more efficient drainage pattern. Successful field development requires an evergreen backlog of opportunities that can be pursued, which is extremely challenging and laborious to generate using traditional workflows. Here, we present a data-driven methodology to automatically deliver a feasible, actionable inventory by combining geological knowledge, reservoir performance, production history, completion information, and multi-disciplinary expertise. This technology relies on automated geologic and engineering workflows to identify areas with high relative probability of success (RPOS) and therefore productivity potential. The workflow incorporates multiple configuration and trajectory constraints for placement of the horizontal wells, such as length/azimuth/inclination range, zone-crossing, fault-avoidance, etc. The optimization engine is initialized with an ensemble of initial guesses generated with Latin-Hypercube Sampling (LHS) to ensure all regions of POS distribution in the model are evenly considered. The advanced optimization algorithm identifies potential target locations with 3D pay tracking globally, and the segments are further optimized using an interference analysis that selects the best set of non-interfering targets to maximize production. Advanced AI-based computational algorithms are implemented under numerous physical constraints to identify the best segments that maximize the RPOS. Statistical and machine learning techniques are combined to assess neighborhood performance and geologic risks, along with physics-based analytical and upscaled parametric models to forecast phase-based production and pressure behavior. Finally, a comprehensive vetting and sorting framework is presented to ensure the final set of identified opportunities is feasible for the field development plan, given the operational constraints. This methodology has been successfully applied to a mature field in the Middle East with more than 90 vertical well producers and 50 years of production history to identify horizontal target opportunities. Rapid decline in oil production and a subpar recovery factor were the primary incentives behind switching to horizontal development. The search covered both shorter laterals accessible as a side-track from existing wells to minimize water encroachment, and longer laterals that could be drilled as new wells. After filtering based on geo-engineering attributes and rigorous vetting by domain experts, the final catalog consisted of 32 horizontal targets. After careful consideration, the top five candidates were selected for execution in the short term with an estimated total oil gain of 40,000 STB/D. The introduced AI-based methodology has many advantages over traditional simulation-centric workflows that take months to build and calibrate a model. This framework automates steps typically performed during the selection of horizontal well candidates by applying advanced algorithms and AI/ML to multi-disciplinary datasets. This enables teams to rapidly run and review different scenarios, ultimately leading to better risk management and shorter decision cycles with more than 90% speedup compared to conventional workflows.

There are several reasons for obtaining gyroscopic surveys in directional wells. A gyro measurement provides reliable data when magnetic measurements are affected by interference from nearby wells; it can significantly reduce the positional uncertainty and provides redundancy data and gross error checks on MWD surveys. However, the complexity and extent of the necessary testing and handling of the tools have prevented widespread adoption, and gyro services have remained limited to "must-have" scenarios. The benefits of solid-state technology and new developments in communication capabilities are gradually changing the way of thinking related to wellbore positioning. The first gyro while drilling tools were introduced in the early 2000s and were based on spinning mass gyro technology. These gyros can be very accurate with low noise levels and drift; however, they are fragile, built with moving parts, and susceptible to calibration shifts. Extensive pre-job testing, validation during job execution and post-job analysis are required to obtain reliable directional survey data. Solid-state gyros have reached the same, or even better, levels of noise and drift without the fragility of their spinning mass counterpart. With different degrees of complexity and coverage, remote operations have been used for many years in the oilfield. Still, the adoption of monitoring gyro services with no personnel at the rig-site has been minimal due to the described complexity of the system and the small volume of jobs that prevented investment and the development of the necessary processes. Solid-state gyro technology addresses these challenges More than 30 gyro-while-drilling jobs have successfully run remotely. The changes in operational procedures forced by the Covid-19 pandemic accelerated the demand for uncrewed operations, and solid-state gyro technology has shown high reliability with zero non-productive time due to tool failures or shifts in the calibration. This new way of working also results in a significant reduction in the environmental impact of the operations as all travel related to personnel and equipment has been reduced and battery life extended by up to 10. Several scenarios related to wellbore positioning and directional drilling greatly benefit by having a gyro in the BHA. The gyro technology and the workflow described in this paper show how this can be done reliably, maintaining the quality of the survey data and reducing the environmental impact.

Conventional ICDs were invented for long horizontal wells to promote a more uniform inflow profile. Later, AICDs were developed, which utilize viscosity contrast between fluids to impose a larger hydraulic resistance in sections with inflow of undesired fluids, like gas and water. However, these AICD technologies cannot be used to choke back inflow of water in reservoirs where oil and water have similar viscosities, and they also tend to impose large pressure drops even for single-phase oil at high flow rates. The objective of the work presented here has therefore been to develop an inflow control technology that removes these limitations. The resulting Density Activated Recovery (DAR™) technology utilizes difference in fluid density rather than viscosity contrast to control fluids downhole. It is a fully autonomous, binary system that is either fully open or closed, where "closed" means that it only allows a small pilot flow. More specifically, it can be considered a "dual ICD" with flow through a large port when open, and a small port when "closed". The flow capacity and choking efficiency are therefore fully defined by the diameters of these two ports. Furthermore, it can close and reopen at any pre-determined water and gas fractions, that are completely insensitive to flow rate, viscosity and Reynolds number. This makes it universally applicable to control any wellbore fluid along the entire reservoir section. After successful prototype testing in 2018, the DAR technology has now undergone a comprehensive full-scale system-qualification program including a final flow performance test where the system was tested at 240 bar and 90ºC with saturated 0.8 cP oil. The tests demonstrated up to seven times higher flow capacity with the density-based DAR technology compared with viscosity-dependent AICD technologies. The system successfully and repeatedly closed and reopened for both gas and water. As oil and water had similar viscosities, the tests also proved how this technology can be used to stop undesired inflow of water in light-oil reservoirs. Being insensitive to flow rate, the DAR system is also insensitive to local variations in pressure and productivity along the reservoir section, which reduces the negative consequences of geological uncertainty and allows the same design to be used at every location in the well. It can also be configured to ensure complete mud removal during well cleanup and can even stop inflow of water in gas wells, where the undesired fluid has higher viscosity than the desired fluid. More importantly, this technology can deliver automated reservoir management to a level where it influences how wells are drilled and fields are developed. Accelerated oil production and the reduced need for reinjection of gas/water will also reduce the associated greenhouse gas (GHG) emissions considerably.

A gas condensate field in the Sultanate of Oman has been developed since 1999 with vertical wells, with multiple fractures targeting different geological units. There were always issues with premature screenouts, especially when 16/30 or 12/20 proppant were used. The problems placing proppant were mainly in the upper two units, which have the lowest permeability and the most heterogeneous lithology, with alternating sand and shaly layers between the thick competent heterolith layers. Since 2015, a horizontal well pilot has been under way to determine if horizontal wells could be used for infill drilling, focusing on the least depleted units at the top of the reservoir. The horizontal wells have been plagued with problems of high fracturing pressures, low injectivity and premature screenouts. This paper describes a comprehensive analysis performed to understand the reasons for these difficulties and to determine how to improve the perforation interval selection criteria and treatment approach to minimize these problems in future horizontal wells. The method for improving the success rate of propped fracturing was based on analyzing all treatments performed in the first seven horizontal wells, and categorizing their proppant placement behavior into one of three categories (easy, difficult, impossible) based on injectivity, net pressure trend, proppant pumped and screenout occurrence. The stages in all three categories were then compared with relevant parameters, until a relationship was found that could explain both the successful and unsuccessful treatments. Treatments from offset vertical wells performed in the same geological units were re-analyzed, and used to better understand the behavior seen in the horizontal wells. The first observation was that proppant placement challenges and associated fracturing behavior were also seen in vertical wells in the two uppermost units, although to a much lesser extent. A strong correlation was found in the horizontal well fractures between the problems and the location of the perforated interval vertically within this heterogeneous reservoir. In order to place proppant successfully, it was necessary to initiate the fracture in a clean sand layer with sufficient vertical distance (TVT) to the heterolith (barrier) layers above and below the initiation point. The thickness of the heterolith layers was also important. Without sufficient "room" to grow vertically from where it initiates, the fracture appears to generate complex geometry, including horizontal fracture components that result in high fracturing pressures, large tortuosity friction, limited height growth and even poroelastic stress increase. This study has resulted in a better understanding of mechanisms that can make hydraulic fracturing more difficult in a horizontal well than a vertical well in a laminated heterogeneous low permeability reservoir. The guidelines given on how to select perforated intervals based on vertical position in the reservoir, rather than their position along the horizontal well, is a different approach than what is commonly used for horizontal well perforation interval selection.

In this paper we present a new type of vibration related to PDC bits in drilling and its mitigation: a vibration coupled in axial, lateral and torsional directions at a high common frequency (3D coupled vibration). The coupled frequency is as high as 400Hz. 3D coupled vibration is a new dysfunction in drilling operation. This type of vibration occurred more often than stick-slip vibration. Evidences reveal that the coupled frequency is an excitation frequency coming from the bottom hole pattern formed in bit/rock interaction. This excitation frequency and its higher order harmonics may excite axial resonance and/or torsional resonance of a BHA. The nature of 3D coupled vibration is more harmful than low frequency stick-slip vibration and high frequency torsional oscillation (HFTO). The correlation between the occurrence of 3D coupled vibration and bit design characteristics is studied. Being different from prior publications, we found the excitation frequency is dependent on bit design and the occurrence of 3D coupled vibration is correlated with bit design characteristics. New design guidlines have been proposed to reduce or to mitigate 3D coupled vibration.

This article deals with the issues related to development of petroleum resources of Western Siberia and looks at one of the most promising development targets – reservoirs of the Achimov Formation. In particular, it discusses geological features of the Achimov rocks, and the difficulties faced by oil companies in development of the Achimov reservoirs due to their low economic viability if traditional approaches to well construction are applied. To make development of such reservoirs economical, new and non-trivial solutions need to be looked for. One of the most promising of them is considered to be multi-hole wells the construction of which allows oil companies to improve the Capex to cumulative production ratio. At the pre-FEED stage the project, geological, hydrodynamic and geomechanical models of the reservoir were built, the most efficient borehole parameters and trajectories were defined, and the optimal hydraulic frac design, number of stages and parameters were selected. The article describes specifics of the work carried out when preparing for pilot tests of the technology, such as: requirements for defining the well profile and selecting the optimal lifting capacity of the drilling rig, selection of a suitable complexity level for the double-hole well design among those considered which meets the drilling requirements, performance of bench tests to confirm operability of the TAML-3 equipment. Further, the article describes results of drilling, completing and commissioning the first double-hole well at the Vyngayakhskoye field, discusses the issues faced when using the completion equipment at the TAML-3 level, and the lessons learned from this project. It also presents results of putting the double-hole well on-stream and compares its production characteristics with those of single-hole horizontal wells drilled within the same well cluster. The experience gained has shown that building the discussed type of wells is technically feasible, and there is a wide potential for improving efficiency of this work through respective organizational and technical measures. The conclusion to this article describes Gazprom Neft long-term plans to build several new wells of this design, and the technology development options such as increasing the length of horizontal segments for both holes and using high-rate multi-stage hydraulic fracturing.

This Extended Reach Drilling (ERD) field re-development of a giant offshore field in the United Arab Emirates (UAE) requires in most cases extremely long laterals to reach the defined reservoir targets. However, certain areas of the field show permeability and / or pressure variations along the horizontal laterals. This heterogeneity requires an inflow control device (ICD) lower completion liner to deliver the required well performance that will adequately produce and sweep the reservoir. The ICD lower completion along with the extremely long laterals means significant time is spent switching the well from reservoir drilling fluid (RDF) non-aqueous fluid (NAF) to an aqueous completion brine. To reduce the amount of rig time spent on the displacement portion of the completion phase, an innovative technology was developed to enable the ICDs to be run in hole in a closed position and enable circulating through the end of the liner. The technology uses a dissolvable material, which is installed in the ICD to temporarily plug it. The dissolvable material is inert to the RDF NAF while the ICDs are run into hole, and then dissolves in brine after the well is displaced from RDF NAF to completion brine, changing the ICDs from closed to an open position. The ability to circulate through the end of the liner, with the support of the plugged ICDs, when the lower completion is deployed and at total depth (TD), enables switching the well from RDF NAF drilling fluid to an aqueous completion brine without the associated rig time of the original displacement method. The technique eliminates the use of a dedicated inner displacement string and allows for the displacement to be performed with the liner running string, saving 4-5 days per well. An added bonus is that the unique design allowed for this feature to be retrofitted to existing standard ICDs providing improved inventory control. In this paper the authors will demonstrate the technology and system developed to perform this operation, as well as the qualification testing, field installations, and lessons learned that were required to take this solution from concept to successful performance improvement initiative.

With rising energy demand, operators in the Middle East are now focusing on developing unconventional resources. To optimize hydraulic fracture stimulation, most of these deep gas wells are required to be drilled laterally and in the direction of the minimum horizontal stress. However, this poses an increased risk of stuck pipe due to hole instability, differential sticking and skin damage due to high overbalance pressures, which makes drilling these wells challenging and costly. Another major challenge in the Middle East is lost circulation due to natural fractures in carbonate reservoirs. Lost circulation currently accounts for loss of approximately $850-900 million USD per year globally across the industry ( Marinescu 2014 ). This paper presents a case study where a holistic approach; combining geomechanics and drilling technologies were employed to address the drilling challenges specific to unconventional and naturally fractured reservoirs. Ultimately, this approach helped the client to mitigate stuck pipe issues, while proposing a physics/engineering-basedmethodology to reduce losses by sealing fractures, hence providing a roadmap to optimized drilling and mitigation of hazards with associated Non-Productive Time (NPT). The paper demonstrates a holistic approach, combining wellbore stability analysis, managed pressure drilling (MPD) and proposes a novel physics/engineering-based methodology for addressing lost circulation challenges. A 1-D wellbore stability model is initially developed to determine the safe operating downhole pressure limits and to effectively assess the drilling risks associated with the planned wellbore orientation. By accurately determining the required bottomhole pressure to prevent wellbore stability problems, managed pressure drilling technology can be implemented to provide improved drilling hazard mitigation by enabling reduced overbalance pressures, constant bottomhole pressure, and faster reaction time by instantaneously adjusting downhole pressures. A bi-particulate bio-degradable system is used as a lost circulation material (LCM). The bigger size cylindrical particles flowing at a pre-defined rate will form a bridge or a plug across the fracture aperture, providing mechanical stability and the smaller spherical particles will seal the gaps in the bridge there by providing an effective sealing of the fracture opening. From experience, implementing these methodologies and technologies in isolation has not provided satisfactory results. This indicates that a partnership which leverages the strengths of the individual disciplines from the early planning stages is necessary to effectively address the drilling challenges posed by unconventional and naturally fractured reservoirs. For the case study highlighted in this paper, the well was drilled to TD in a timely manner, while maintaining the integrity of the hole, hence confirming the viability of this approach. In addition, the physics and engineering design workflow for bi-particulate bio-degradable LCM demonstrates how it can be effectively deployed to mitigate lost circulation without skin damage to the formation

In an oil field, openhole multilateral maximum reservoir contact (MRC) wells are drilled. These wells are typically equipped with smart well completion technologies consisting of inflow control valves and permanent downhole monitoring systems. Conventional flowback techniques consisted of flowing back the well to atmosphere while burning the hydrocarbon and drilling fluids brought to surface. In an age of economic, environmental and safety consciousness, all practices in the petroleum industry are being examined closely. As such, the conventional method of flowing back wells is frowned upon from all aspects. This gives rise to the challenge of flowing back wells in an economic manner without compromising safety and the environment; all the while ensuring excellent well deliverability. By utilizing subsurface smart well completion inflow control valves, individual laterals are flowed to a separator system whereby solid drill cuttings are captured and discharged using a solids management system. Hydrocarbons are separated using a separation vessel and measured before being sent to the production line toward the field separation facility. Permanent downhole monitoring systems are used to monitor pressure drawdown and subsequently control the rate of flow to surface to ensure reservoir integrity. Following the completion of the solids and drilling fluid flowback from the wellbore, comprehensive multi-rate measurements at different choke settings are obtained to quantify the well performance. This paper looks at the economic and environmental improvements of the adopted zero flaring cleanup technology and smart well completions flowback techniques in comparison to conventional flowback methods. This ensures that oil is being recovered during well flowback and lateral contribution to overall flow in multilateral wells. In addition, it highlights the lessons learned and key best practices implemented during the cleanup operation to complete the job in a safe and efficient manner. This technique tends to set a roadmap for a better well flowback that fulfills economic constrains and protects the environment.

Conventional downhole dynamic characterization is based on data from standard production logging tool (PLT) strings. Such method is not a feasible option in long horizontal drains, deep water scenarios, subsea clusters, pump-assisted wells and in presence of asphaltenes/solids deposition, mainly due to high costs and risk of tools stuck. In this respect, intrawell chemical tracers (ICT) can represent a valid and unobtrusive monitoring alternative. This paper deals with a new production allocation interpretation model of tracer concentration behavior that can overcome the limitation of standard PLT analyses in challenging environments. ICT are installed along the well completion and are characterized by a unique oil and/or water tracer signature at each selected production interval. Tracer concentration is obtained by dedicated analyses performed for each fluid sample taken at surface during transient production. Next, tracer concentration behavior over time is interpreted, for each producing interval, by means of an ad-hoc one-dimensional partial differential equation model with proper initial and boundary conditions, which describes tracer dispersion and advection profiles in such transient conditions. The full time-dependent analytical solutions are then utilized to obtain the final production allocation. The methodology has been developed and validated using data from a dozen of tracer campaigns. The approach is here presented through a selected case study, where a parallel acquisition of standard PLT and ICT data has been carried out in an offshore well. The aim was to understand if ICT could be used in substitution of the more impacting PLT for the future development wells in the field. At target, the well completion consists of a perforated production liner with tubing. The latter, which is slotted in front of the perforations, includes oil and water tracer systems. The straightforward PLT interpretation shows a clear dynamic well behavior with an oil production profile in line with the expectations from petrophysical information. Then, after a short shut-in period, the ICT-based production allocation has been performed in transient conditions with a very good match with the available outcomes from PLT: in fact, the maximum observed difference in the relative production rates is 5%. In addition, the full analytical solution of the ICT model has been fundamental to completely characterize some complex tracer concentration behaviors over time, corresponding to non-simultaneous activation of the different producing intervals. Given the consistency of the independent PLT and ICT interpretations, the monitoring campaign for the following years has been planned based on ICT only, with consequent impact on risk and cost mitigations. Although the added value of ICT is relatively well known, the successful description of the tracer signals through the full mathematical model is a novel topic and it can open the way for even more advanced applications.