Abstract Rotary steerable systems (RSS) and steerable motors pose their own unique challenges when modelling the bottomhole assembly (BHA) directional behavior. This paper aims to present a methodology that allows the anticipation of problems such as mechanically stuck pipe or lock up situations when running in hole casing or completion strings. The methodology consists of 3 tasks: evaluation of intermediate doglegs and wellbore tortuosity using a unique Rock-Bit-BHA analysis, modelling of the casing deformation including potential centralization and then modelling the run in hole (RIH) of the completion. The directional capabilities of a BHA are affected significantly by the selection of the drilling bit, type of directional drilling driving system and the type of formation. The resulting trajectory can be either very smooth or very tortuous with significant additional local doglegs. The deformation of the casing as well as the completion post buckling analysis is completed using a robust and field validated 3D stiff string Torque & Drag & Buckling model. This methodology can be applied before, during or after the well has been drilling. Used before or during the well construction process, an indication can be given as to whether the casing or completion can reach total depth (TD) using planned or actual data. Used after a lockup or stuck pipe incident, the methodology can give an indication if tortuosity was a contributing factor. Various field cases are presented and clearly show the benefit of the methodology including post-analysis of stuck standalone-screen (SAS) completion string in complex 3D drain and pre-analysis of completion run in hole (RIH) targeting a specific drain. Correctly evaluating the risk of BHA, casing and/or completion strings getting stuck or locked-up when RIH can ultimately provide a template for ultimate reduction of non productive time (NPT). This modeling results has been verified and discussed in the field.

Abstract Highly efficient multi-stage hydraulic fractured horizontal wellbores are the dominant completion method for many basins worldwide. This completion workflow is followed with the well start up operations, usually consisting of the frac-plug drill out (FPDO) and the well flowback, designed for preparing the well to the production period. Poor management of FDPO and flowback operations on wells with freshly constructed hydraulic fractures, may jeopardize the investments made in completing the well, and may seriously reduce the well’s profitability. Previously reported results show that flowback and initial production practices have a major impact on proppant production, maintenance and disposal costs, and the subsequent well performance. In this paper we present the summary of the results obtained from the analysis of over 200 FPDO and flowback operations in the United States and Argentina. These results show that operating a well within the safe stability limits of the hydraulic fracture network minimizes risk of fracture damage and maximizes well performance. Earlier it was shown that typical plug drillout operations consists of a series of underbalance, overbalance and balance periods. Multiple rapid transitions between these conditions and performing plug drillout operations outside of the fracture stability limit, was shown to destabilize the proppant pack and mobilize proppant from the fractures. In this paper we evaluate the impact of the various plug drillout strategies on the proppant distribution in the fracture, and draw conclusions about the strategies that help to preserve fracture conductivity. We also demonstrate that using high-frequency monitoring of the surface rates is key for managing plug drillout operations to minimize mobilization of the proppant from hydraulic fractures. Use of the recently introduced Secure Operating Envelope (SOE) concept was found to be very beneficial for managing well flowback and the production operations. In this paper we demonstrate how the use of the SOE methodology was used for identification of the root cause of the proppant flowback and deriving the appropriate choke management strategy for solving this problem. At the end we conclude that majority of the highlighted problems can be solved through optimizing the well start up operations as a part of the entire well construction process with making changes to the well construction workflow. Implementing certain changes to fracture treatment design should enable maximization of the well production performance and optimize the well economics.

Abstract Oil and GAS operators planned to upgrade several existing oil production facilities. The existing jackets are demolished and removed from the seabed with only the conductor wells being retained from the facility. The existing offshore oil and gas platforms could be enhanced to operate for some more years. The jacket piles from 1.5m below seabed will be cut and together with the jacket demolished. The remainder of the piles below seabed will be left in situ. A new 4-leg standard jacket will be slipped over the existing wells. New conductor wells are to be added to the new jackets. The new jacket will be piled to the seabed with new piles. During design it will be ensured that the new piles do not clash with the exiting piles below seabed. The new jackets the geometric Centre coordinates will be dependent on the existing well layout and the location of additional wells. The jacket locations will be checked for clashes with the existing abandoned piles and feasibility of installing new wells. The focus of this paper is on the strategies applied in executing Brownfield works for many offshore platforms in Arabian Gulf by National Petroleum Construction Company (NPCC). The case study demonstrates the installation of new four legged Simplified, Standardized and SIMOPS jacket structures onto existing wells using a simplified design approach, standardized seafastening arrangements that requires less offshore work, minimal interface and operations shutdown of live equipment. To ensure the safe and minimized risk installation operation of Slip over jackets at the existing offshore filed, the cost effective installation methods were devised and implemented to have the successful installation of slip over jackets. These installation strategies help EPC contractor achieve the early completion of the jacket installation in a cost effective way. This strategy places the companies in a better shape such that after the price fluctuation periods, they will be more prepared to face new challenges in developing new fields that will improve their bottom lines and be leaner in their operations. Hence, Operators and EPC Contractors tend to focus on cost efficient and sustainable approaches that will maintain the profit margin and gain competitive advantage.

Abstract For years downhole monitoring and control have been widely used technologies to improve production and reservoir management. At the same time drilling technology has evolved and resulted in a rise of deep and complex multi-lateral wells. A well path may cover multiple production zones and connectivity between, and performance of production zones are often difficult to quantify. These challenges have contributed to a growing demand for information and control directly at the reservoir. This paper will show a reliable method to bridge the gap between the upper and lower completion for both control and data flow. The method is a combination of two well proven systems, namely a cabled permanent downhole monitoring system that is connected to the surface with a tubing encapsulated conductor and instrumentation and control tools that are placed in the production zones of the laterals and are operated wirelessly. Extending the capabilities of both systems, a new wireless interface incorporated at the lower end of the cabled monitoring system enables duplex communication with the wireless instruments and tools in the lower completion. Communication between the wired system and wireless operated instruments may be based on acoustic or electromagnetic signals. The combination of the two technologies provides an innovative new method to overcome the challenge of making a physical connection between the upper and lower completion for monitoring and control data transmission and may also be adapted to access instrumentation and controls in multiple laterals. The adaption of the technology is straightforward as the standard interface card is placed in a surface acquisition unit for dry trees and in the subsea control modules for wet trees. The interface card can send commands and log data from both the wired instrumentation in the upper completion and the wireless operated instruments and controls in the lower completion.

Abstract The continuous and rigorous endeavor in identifying key project successes or failures has been one of the most celebrated effort within the fraternity to advocate good project management implementation. Although the delivery method is unique from one project to another, perceivably there is no right or wrong formula that ensures outright success. It is often regarded that having an exceptional project manager leading a team that pays attention to collaboration between the project team and the contractors or manufacturers, guarantees a successful project delivery. What is rarely looked upon is the contribution of the operations and maintenance personnel embedded as part of the team, which plays a vital role to the smooth and seamless transition from the task-oriented project, to the product-oriented operations and productions phase. Early involvement of this sort enables majority of the pain points anticipated during commissioning, start-up and finally during the handover period to be addressed much earlier during detailed engineering and construction phases. The accomplishment of the recently completed Spheripol and Spherizone polypropylene units as part of the giga-project Refinery and Petrochemical Integrated Development (RAPID) which is located within the Pengerang Integrated Complex (PIC) in Malaysia, gives us the best insight on how project delivery can improve and flourish by putting the emphasis on small things that matter. Standing at USD 27 billion, PIC, the largest downstream investment by PETRONAS in Malaysia, consists of an integrated refinery and petrochemical complex, supported by several facilities which includes a raw water supply and treatment plant, an air separation unit, a cogeneration plant, a deep-water terminal and a regasification terminal. Like other plants complexes, it also has its own centralized utilities facility. Not many would think that setting the operational elements and getting the operations personnel involved as part of the team prematurely, will minimize technical gaps once the facility starts its operations. However, this unique approach has proven to be effective and successful for a major integrated project like RAPID. The operational elements mentioned above include progressive participation and deployment of operations and maintenance personnel during front end and pre-award of execution contracts, assurance reviews (engineering, constructability and safety) and mechanical completion walkdowns. This gradual involvement evolves into a full leadership role during commissioning up until the process of starting up the plant. This study will show how the close collaboration between projects and operations teams, towards the successful delivery and integration of RAPID polypropylene plant can never come too early.

Abstract Inflow control device (ICD) completions are becoming a crucial part for many green and brown field developments. However, a typical ICD completion requires a washpipe or inner string to provide fluid circulation, displacement and setting of openhole hydraulic-mechanical packers, which increases operational time, risks and costs. A typical installation process has to follow a series of operational steps to ensure successful deployment of ICD completions. Those necessary operational steps are traditionally achieved using washpipe or an inner string that is run inside the lower completion bottomhole assembly (BHA). This unique and advanced ICD completion design uses proven sliding-sleeve technology that will be run in the closed position to provide fluid circulation, displacement and setting of openhole hydraulic -mechanical packers, and then hydraulically activated to the open position to allow for reservoir-to-well communication. It also incorporates a mechanical-shifting mechanism for future reservoir management and control. The new and advanced ICD completion has undergone a rigorous testing program to ensure the design will deliver those operational requirements and perform appropriately under the worst well operational conditions that are expected during the field life. Following completion of the testing program, the advanced ICD completion was deployed flawlessly in a carbonate reservoir well in the Middle East, representing the first successful deployment globally. The system has functioned as expected with clear surface indication throughout the different operational steps and the final establishment of reservoir-to-well communication which was evidenced by the increase in the well head pressure (WHP). Furthermore, the individual ICD open or closed-sleeve status was verified through production logging (PLT) and coil tubing (CT) shifting operations. The paper describes a comprehensive qualification testing program for the advanced ICD completion design to best serve those well-installation requirements without the need of washpipe. Furthermore, it details the actual well deployment which resulted in improved overall well completion design and operational efficiency.

Abstract Extended reach drilling (ERD) wells involves numerous drilling challenges that in many cases causes cost overrun and delays for such wells. This paper presents a new approach used to drill a 10,000 ft long departure using a slim design to replace the conventionally well design that uses heavy casings. This approach eliminated the 22" hole section and the associated 18 5/8" casing reducing 20 days form the well duration and saving $1 million. Achieving such a long departure requires a shallower kick off and requires building inclination as early as possible crossing reactive shales and need high mud weight to guarantee hole stability. Historically an additional casing string used in order to isolate a loss zone prior to the shale formation to drill it with high mud weight. This approach limited the inclination across shales and penetrated it along with the loss zone in same section by controlling the WBM weight to be just high enough for bore stability and minimizing the loss rate but increasing the challenges in the next sections. Drilling the single horizontal oil producer well started with a 16" hole size, kicked off at 300 ft and built to 22-degree inclination in that section and isolated with 13-3/8" surface casing. A 12-1/4" hole was drilled across the loss zone and reactive shales formation keep the WBM weight as 9.4 ppg (70 PCF) while drilling the loss zone and increased later to 9.9 ppg (74 pcf) prior to drilling the reactive shale where the inclination was limited to 27 degree across it and built later to 32 deg at the end of 12 ¼" hole section and isolated with 9-5/8" production casing.8 ½" hole section was drilled with 12.3 ppg (92 pcf) OBM in order to built 82 deg before penetrating the reactive shale and hold it tangent to cover the maximum departure and built to 90 deg to land in target reservoir with total departure of 10,755 ft and isolated with 8,150 ft long 7" production liner, followed by 4,000 ft 6‘‘ horizontal open hole. This novel light casing design avoided drilling a hole section of 22‘’ and the associated 18-5/8" casing, saving at least 20 days in well duration and nearly $1 million in well cost. The new slim well design explained in this paper, which is used to drill long departure well with 10,000 ft, is the first of its kind in ADNOC Onshore field. It has proved that such long departure wells can be completed with light casing design and achieve 100% integrity.

The development of marginal volumes in the Jasmine field is part of Mubadala Petroleum's overall strategy to extend the field's life. This development is accomplished by progressively exploiting increasingly challenging prospects. This paper highlights two case studies to illustrate how Mubadala Petroleum has successfully developed marginal prospects to unlock the Jasmine field's remaining potential. Prospect identification begins with integrated subsurface studies focusing on contingent resources. Several studies were conducted to determine the right technology to mature these marginal prospects. These prospects often involve the requirement to drill Extended Reach Drilling (ERD) wells. This is due to the fact that some platforms are slot constrained, such that wells cannot always be drilled from the nearest platform. One of Mubadala Petroleum's solutions was to drill a horizontal well with a completion that uses an Autonomous Inflow Control Device (AICD) to optimize and enhance oil production. This combination of AICD and ERD horizontal wells has proven successful in the Jasmine field's continuing development. Two wells in this case studies were drilled during the 2018 and 2019 drilling campaigns, illustrate how marginal volumes are developed in the Jasmine field, with each case having unique objectives and challenges. In 2018, one horizontal well was drilled, with an aim to enhance recovery efficiency in the viscous oil reservoir. The well was drilled close to the top reservoir, AICD devices were installed in conjunction with a sand screen to delay water breakthrough, and the well has been in production for two years. The overall strategy was effective in delaying water breakthrough. In 2019, a horizontal well was drilled to develop a relatively small 14ft oil rim below a thick gas cap reservoir. This well was the longest ERD well in the Gulf of Thailand. The well was also successfully drilled and geosteered at 4-5 ft TVD below the gas cap. AICD's were installed to balance the gas cap expansion and aquifer support to optimize oil production. The well has produced at a stable oil rate of 500-600 bbls per day with minimal gas and water production, up to the present date, confirming the validity of AICD technology in reducing the production of unwanted fluids. The AICD has been shown to play a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. AICD completions also help to enhance production recovery from viscous oil reservoirs. Moreover, ERD drilling has improved the feasibility of several remote prospects and minimized the slot availability constraint in the Jasmine field.

Drilling and completing wells for hydrocarbon production comprise the major cost of well operations. Slim-hole drilling can significantly reduce drilling costs, making low producing reservoirs economically viable. However, a number of challenges are associated with slim-hole wells. A major challenge encountered while deploying lower completions in long horizontal slim-hole wells is stuck pipe, as the wellbore diameter is less than six inches, allowing restricted clearance between the wellbore and completion equipment. Stuck pipe incidents can cause significant non-productive time (NPT), additional high costs, and the possibility of compromising the well objective. Stuck pipe incidents may require sidetrack operations in the worst cases, which may considerably change the planned well design and delay the overall project, along with increasing costs. Drilling in the minimum stress direction with heavy mud weight and high overbalance pressure adds to the challenge in deploying completions in HPHT slim-hole wells. While deploying the lower completions in slim-hole wells, many factors come into play and each factor has a critical role in the success of the operation. After conducting a detailed study on several HPHT slim-hole gas wells in Middle-East region, a risk matrix was developed for a specific well-bore diameter, by identifying some common variables. Based on potential chance of occurrence, a certain value was assigned to each variable. The risk mitigation plans are driven by the risk matrix variables. Using this risk matrix, the occurrences of stuck pipe incidents in critical HPHT slim-hole wells that initially tend to have high chances of stuck pipe were significantly reduced. The risk matrix presented in this paper successfully mitigated stuck pipe incidents from occurring and has saved millions of dollars in associated costs. The matrix played a key role in operator's drilling operations and was adapted in operations as an important tool to evaluate final wellbore conditions prior to selection of the optimum completion type. This paper presents a highly effective risk matrix that significantly minimizes stuck pipe incidents during drilling/completion operations of slim-hole gas wells.

Inflow Control Device (ICD) completions have been used widely in the energy industry to balance the inflow of produced fluids, while delaying water breakthrough. Improving the reservoir drainage results in higher oil recovery. Traditional completions are typically deployed with washpipe to provide washdown and circulation capability. This is especially advantageous for Run In Hole (RIH) through tight spots and extended-reach wells. A tailored ICD design with dissolvable materials was tested and optimized for Middle Eastern fields with the first successful installation in UAE of a washpipe-free ICD completion. The washpipe-free adjustable ICD completion utilizes a combination of permanent and dissolvable temporary ICD plugs. A range of dissolving materials were developed and tested in a variety of representative downhole conditions, including temperature and pressure variables. The dissolvable materials were tailored specifically to suit the fluid program and fluid additives, common to the Middle East. Multiple plug designs were subjected to small-scale and full-scale tests. Computational Fluid Dynamics (CFD) simulations evolved the design of the ICD housing to ensure that the dissolution fluid would reach the ICD plugs. The dissolution rates of the dissolvable materials were empirically established at representative downhole temperatures with field fluid samples. The degradation and pressure integrity of the materials was validated in small- and full-scale testing. Through full-scale testing, the operational sequences during RIH including displacement and filter cake breaker spotting were replicated with representative pressures, fluid rates, bottom hole temperatures (BHT), and fluid compositions used in the Middle East field. The validated ICD plugging rod technology was successfully run in the UAE in an extended-reach horizontal well. The permanent plugs allowed for customization of the completion inflow profile as per the most recent logs, while the dissolvable temporary plugs provided a completion string with pressure integrity while running in hole - capable of washdown, circulation, and filter cake treatment placement. After installation, the temporary plugs dissolved, opening the completion to production through the ICDs for improved reservoir management. The ICD with dissolvable technology allowed deployment of the completion successfully to target depth (TD) with the pressure integrity required for the displacement operations. In not running and retrieving an inner string, and achieving wellbore displacement at a faster rate, time savings for the 6000 ft OH completion were estimated between 35-50 hours, with an estimated cost saving of a half-million dollars.

Unmanageable losses through carbonate formations led to pumping water through the drill pipe and heavy mud cap in the annulus to drill with total losses. Although this technique overcomes the need to fly mix drilling fluid, it adds the complication of pumping heavier mud cap into the annulus. Pressurized Mud Cap Drilling (PMCD) was introduced the first time in the project to eliminate the requirement of mud cap for improve wellbore condition, efficient well control and to optimize the overall cost while drilling with total losses. As mud cap density increases based on reservoir pressure, so does solids concentration in mud cap. Apart from mud cap getting extremely expensive at higher densities, it deteriorates hole condition due to continuous addition of solids especially for horizontal wells where solids keep piling up on the low side of the wellbore. With total losses in the reservoir, drilling is followed by image log, followed by reaming run and finally open hole completion runs to isolate those fractures. On wells where higher density mud cap was used, severe hole problems leading to stuck pipe were faced either during logging or open completion runs. On most of the occasions, solids of mud cap have been proven as the root cause for worsening the situation. PMCD has been introduced as a solution to such high-pressure wells to drill and complete them with total losses more efficiently and cost-effectively. It not only reduces the volume of solids dumped in the wellbore in the form of mud cap thus improving the hole condition but also saves the immense cost of mud cap which is especially massive for long laterals while dealing with long reaming operations. The above motivation of finding a solution for drilling in total loss environment emerged from one of the wells where pipe conveyed logging string (TLC) got differentially stuck while pumping a 90 pcf mud cap. The pipe could not be recovered even after cutting it inside the casing shoe confirming it was packed off with solids laden mud cap. The well was sidetracked and was completed with PMCD successfully without any complications. After that job, PMCD has been implemented in five other land wells successfully and being recognized as standard practice for drilling high-pressure wells with total losses. This paper illustrates the challenges faced by turn key project team due to total losses and drilling with mud cap, and overview of PMCD procedures, comparison of mud cap and the inherent advantages of PMCD over mud cap drilling. It provides details of the well which could only be recovered using PMCD after sidetrack due to stuck pipe.

An extreme-performance polymer-locked wireline cable overcomes the conveyance challenges in tortuous wellbores, enabling the acquisition of high-quality production logging data in extended-reach drilling (ERD) wells. The use of this technology enabled an operator in the UAE to successfully evaluate the downhole production and reservoir properties in four extended-reach wells drilled from an artificial island. Production logging data acquisition using conventional wireline cables is challenging in such wells because of extreme cable tensions. This paper presents a case study about a novel approach of combining an extreme-performance polymer-locked cable and high force tractors to successfully convey production logging tools in an extended-reach well, where previous attempts with two conventional wireline cable types had failed. The new approach is based on analyzing the drag forces acting on the cable in the wellbore and modeling the tortuosity of the wells for determining optimal cable and tractor properties to minimize these effects. Based on this in-depth analysis, high-strength, torque-balanced, polymer-locked coaxial cable and high-force tractors with large wheels are selected for the job. With meticulous risk management and establishing a core team of key personnel, including field operations, the operator, and the product manufacturing center, this new technology is successfully deployed. Production logging tools are successfully conveyed to the maximum depth of 27,800 ft, and safely retrieved from the well. Excellent flowing and shut-in log data are recorded in a single descent, making it possible to accurately quantify zonal contributions from this horizontal lateral for the first time. Good tension profile with new cable shows the value of torque-balanced cables in high-tortuosity well profiles. The success of the job created confidence in conducting safer, more efficient intervention in maximum reservoir contact development wells. It demonstrates the value gained by deploying advanced high-strength polymer-locked coaxial cables in combination with high-force tractors.

Many wells in the Bu Hasa field in Abu Dhabi are completed with near-horizontal or horizontal laterals in the consolidated Lower Cretaceous carbonate formations. These slim barefoot completions allow improved production and drainage from the good permeability formations in the field, however surface production measurements do not tell the full story on the contributing zones downhole. To improve the reservoir management many production logs with specialized logging technology developed for horizontal wells with multiphase flow, are undertaken in the field. This paper presents a case study of one of these wells that was showing less than expected oil production along with a significant but abnormal water cut. Production logging was done to acquire an inflow profile along the lateral, and a pulsed neutron log for formation fluid saturation was also acquired to diagnose any increased water saturation zones. The production profile showed that less than 40% of the open hole lateral length was contributing and that most of the water was coming from a specific section of the well. The formation fluid saturation profile confirmed good oil saturation across the whole lateral as was expected but there was a clearly higher water saturation across the water-producing section of the open hole. Corrective action was taken on the well after these logs with a completion change incorporating various Inflow Control Devices (ICDs) for the lateral section, and gas lift mandrels for improved lifting capability if required in the future. The lateral was then acid stimulated and put back on production. A second production log, again in combination with the pulsed neutron saturation log, was acquired to review the changes in the downhole inflow profile after the completion change. This profile showed that all sections of the lateral were now contributing effectively to the total oil production confirming the effectiveness of the new completion. Water was still coming from the higher water saturation zone that was again observed on the pulsed neutron saturation analysis, however it was apparent that the AICD was controlling the water entry as per design. Surface production measurements indicate reduced water cut and improved oil production confirming good success with the overall intervention. Currently water cut on the well is still slowly but continuously decreasing while the oil production is also improving. Continued monitoring will provide additional feedback for future water conformance operations in the field to assist in improving recovery factor from the reservoir.

ADNOC Group of Companies are embarking on drilling many of development wells in the upcoming years to achieve the forecasted production mandates. Therefore, the wells completion should be designed to cater for the following reservoir requirements as per as per company expectations: ▪ Full accessibility (to TD) for production logging and stimulation. ▪ Flexibility for conformance control. ▪ Defined production allocation. ▪ Fit for purpose completion that can absorb the change in reservoir dynamics throughout well life. The current practice of completing the horizontal wells as open hole "bare-foot" completion and geosteering practice might save some short-term cost, but it may impact the hole accessibility and cost more in the long term. Horizontal well application is one of the key development strategies that will improve the sweeping efficiency and recovery to minimize field development cost by reducing well counts. Longer horizontal require lower completion liners to meet the objectives of the well. Full multi- disciplinary input are needed to properly install an effective lower completion, but robust design often brings strong performance. This paper describes the outcomes of accessibility, geo-steering practices evaluation, fundamental criteria and workflow for selecting the most suitable lower completion design for new and sidetracked wells to achieve ADNOC's production mandates while complying with completion requirements and adhering to reservoir management guidelines. The objective is to optimize the procedures as per ADNOC guidelines in designin, planning and deploying horizontal wells including the Well Post Rig Operation & Monitoring Process, Lessons Learned and assuring full accessibility while meeting integrity and quality of the development wells for future prognosis. The main drivers and objectives for running lower completion are listed below: ▪ Enabled to maximize reservoir contact aiming for cost and production optimizations ▪ Full Accessibility to allow PLTs, Stimulation and re-stimulations. ▪ Compartmentalized lower completion for remedial actions ▪ Achieve uniform flow conformance utilizing ICVs & ICDs ▪ Mitigate and manage water production

Interest is high to reliably run single-trip completions without involving complex/expensive technologies. The reward: significantly reduced rig time and completion costs. As described herein, a unique pressure-activated sliding side door (PSSD) valve was developed and field-tested to open without intervention after completion is circulated to TD and liner hanger and open-hole isolation packers are set. A field-proven sliding-sleeve valve that required shifting via a shifting tool run on coil tubing, slickline or wire-line, was upgraded to open automatically after relieving tubing pressure once packers (and/or liner hanger) are set. This PSSD technology, which is integrable to any type of sand control screen, is equipped with back-up contingency should the primary mechanism fail to open. Once opened, the installed PSSDs can be shifted mechanically with unlimited frequency. The two-or three-position valve can be integrated with ICDs (includes AICDs/AICVs) and allows mechanical shifting at any time after installation to close, stimulate or adjust ICD settings. After a computer-aided design stage to achieve all the operational/mechanical requirements, prototypes were built and tested, followed by several field installations. The design stage provided some challenges even though the pressure-activation feature was being added to a mature/proven SSD technology. Prototype testing in a full-scale vertical test well proved invaluable as it revealed failure mode that could not have appeared in the smaller-scale lab test facilities. Lessons learned from the first field trial helped improve onsite handling procedures. PLT logs run on first installation confirmed the PSSDs with ICDs opened as designed. The second field installation involved a different size and configuration, where PSSDs with ICDs performed as designed. The unique two-or three-position PSSD accommodates any type of sand control or debris screen and any type of ICD for production/injection, which can be easily adjusted at the wellsite. The scope of application is extremely broad. Consequently, more wells that normally could not justify the expense of existing single-trip completion technologies can now benefit from the enormous cost savings of single-trip completions, including ones that require ICD and stimulation options.

The use of Inflow Control Technologies (ICTs), both passive and active, has been motivated by the technology's ability to significantly improve the overall production from a reservoir. Increased oil production combined with reductions in volumes of both water and gas should be expected if these technologies are deployed correctly. These technologies may also affect the total reservoir drainage in a positively manner with less energy used for long term pressure support as result. ICTs are available in passive, active and autonomous versions, all with different physical working principles. Even though some of these are used world-wide, the lack of best-practice advisory documents for planning, implementation, and operation effectively hinder further acceleration of its deployment. Since the first inflow control device (ICD) was patented in 1992, it is response to varying production rates, phase fractions and reservoir pressures that has been addressed, tested, and modelled by many instances. Some of these models are available in today's commercial reservoir simulators, although with poor accuracy. Today, 28 years after the first ICD patent, an important challenge to widespread deployment of the technology is believed to be the lack of established best-practice documents and adequate simulation models. This may hinder efficient comparison of the different technologies against each other and alternative barefoot completions. This paper presents the establishment of such best-practice documents and the development and implementation of generic, effective, and high accuracy simulation models with the ambition to enable qualified selection processes within the different operating companies. The project presented in this paper presents best practice workflow for selecting best ICD completion and the modelling challenges for these completions and their impact on the total drainage from the reservoir. The project has unveiled new understanding that led to drastic changes in the way ICD completions should be evaluated and compared by the operator to ensure maximum recovery.

Project schedule delay and cost overrun have become a normal matter to witness and at a certain point, it textures almost likely that it would be an inevitable result. Such result could be avoided if we identify the causes of delay and try to mitigate the challenges early phase in the project. An effective Project Manager manages all aspects of EPC project and he must understand the causes of problems. This case study aims to explore problems faced in EPC projects that lead to cost overrun and schedule delay, and to explore good practices to minimize impact on overall project. The methodology adopted consists of survey, interviews and case study approach. A survey was used to collect the common causes of EPC Project delays and cost overrun. An interview approach used to find out significant delay and success factors together with effective management practices collected from survey. Later, case study approach is used to validate the information gathered previously and to understand the relation and consequences of each factor. The interviewee were project managers, project controls manager, construction manager, discipline engineers, subject matter experts and client representatives, etc. from several EPC contractors and clients. There are several causes of EPC projects delay and cost overrun and every project may have its own challenges but many found to be common among projects. Sometimes, it may be a single trigger event that leads to delays or a combination of events. The case study reveals that major factors contributing to schedule delay and cost overrun are mostly related to project complexity, aggressive unrealistic schedule, weak or poor planning and control, inherited bidding inaccuracies and estimation mistakes, ineffective leadership and poor decision-making, absence of project management practices, etc. Also, design changes, delay in placing POs, lack of team competency, late client approvals, late vendor information, delay in PTW issuance, inadequate construction resources, quality issues and reworks, and ignoring previous project's lesson learned. Further most, poor risk management, poor interface management between project stakeholders contributes to cost overrun and delays. This case study findings may be helpful to EPC contractors, clients, project sponsors, project managers, construction managers and other stakeholders to understand the major factors, causes and problems that they may face during EPC project lifecycle and how to overcome such challenges effectively. This case study can be viewed as a lesson learned approach. This study will guide them in developing and adopting necessary effective and efficient project management practice to complete the EPC projects within budget, on schedule with good quality, and safety. Stakeholders’ awareness about causes of delay give them more options and improve capability in problem-solving throughout the project life-cycle.

The evaluation of injection efficiency is an important component of monitoring oilfield development; it is often complicated by well design, such as horizontal wells, dual or triple completions, and the use of inflow control devices (ICDs). This paper demonstrates how standard production logging (PL) measurements can be improved with the addition of a high sensitivity noise log and a quantitative temperature analysis that is sensitive to flow behind the tubing and casing. The latest generation noise tools are highly sensitive instruments that record data during multiple short duration stations. The tools acquire noise energy across a wideband spectrum ranging from 8 to 60,000 Hz. To improve interpretation and visualization, the noise data is separated into two displays: an ultra-low frequency narrowband spectrum (8 to 4,000 Hz) and a wideband spectrum (100 to 60,000 Hz). The implementation of high-resolution temperature data with thermal modeling enables improved multiphase flow profiling using the Joule-Thomson effect and near-wellbore temperature behavior in the surrounding formations. The integration of the noise tool and temperature modelling enables the detection of very low rate fluid flow that is not otherwise detectable with conventional production logging tools (PLT) and the quantification of multiphase flow behind the pipe in multi-barrier completions. This paper includes three case studies that demonstrate the integration of noise spectral data, temperature modeling, and spinner data. The first case is a single-string vertical injector well with separate injection at various layers. In this case, the well completion was challenging because the upper production interval was located behind the tubing. In the second example, the injection distribution changes under different flow rate conditions. At a high injection rate, the formation fracture pressure is exceeded; at low flow, the injection is below the fracture pressure. These results demonstrate that it is possible to qualitatively determine all injection intervals by noise logging and to quantitatively estimate the fluid distribution by thermal modeling, which was used to plan successful well workovers and restore injection. This technology identified zones that were taking injection that other conventional tools failed to identify, significantly improving the understanding of water injection conformance in the super giant Burgan field waterflood.

Inflow control device (ICD) completions are becoming a crucial part for many green and brown field developments. However, a typical ICD completion requires a washpipe or inner string to provide fluid circulation, displacement and setting of openhole hydraulic-mechanical packers, which increases operational time, risks and costs. A typical installation process has to follow a series of operational steps to ensure successful deployment of ICD completions. Those necessary operational steps are traditionally achieved using washpipe or an inner string that is run inside the lower completion bottomhole assembly (BHA). This unique and advanced ICD completion design uses proven sliding-sleeve technology that will be run in the closed position to provide fluid circulation, displacement and setting of openhole hydraulic -mechanical packers, and then hydraulically activated to the open position to allow for reservoir-to-well communication. It also incorporates a mechanical-shifting mechanism for future reservoir management and control. The new and advanced ICD completion has undergone a rigorous testing program to ensure the design will deliver those operational requirements and perform appropriately under the worst well operational conditions that are expected during the field life. Following completion of the testing program, the advanced ICD completion was deployed flawlessly in a carbonate reservoir well in the Middle East, representing the first successful deployment globally. The system has functioned as expected with clear surface indication throughout the different operational steps and the final establishment of reservoir-to-well communication which was evidenced by the increase in the well head pressure (WHP). Furthermore, the individual ICD open or closed-sleeve status was verified through production logging (PLT) and coil tubing (CT) shifting operations. The paper describes a comprehensive qualification testing program for the advanced ICD completion design to best serve those well-installation requirements without the need of washpipe. Furthermore, it details the actual well deployment which resulted in improved overall well completion design and operational efficiency.

Extended reach drilling (ERD) wells involves numerous drilling challenges that in many cases causes cost overrun and delays for such wells. This paper presents a new approach used to drill a 10,000 ft long departure using a slim design to replace the conventionally well design that uses heavy casings. This approach eliminated the 22" hole section and the associated 18 5/8" casing reducing 20 days form the well duration and saving $1 million. Achieving such a long departure requires a shallower kick off and requires building inclination as early as possible crossing reactive shales and need high mud weight to guarantee hole stability. Historically an additional casing string used in order to isolate a loss zone prior to the shale formation to drill it with high mud weight. This approach limited the inclination across shales and penetrated it along with the loss zone in same section by controlling the WBM weight to be just high enough for bore stability and minimizing the loss rate but increasing the challenges in the next sections. Drilling the single horizontal oil producer well started with a 16" hole size, kicked off at 300 ft and built to 22-degree inclination in that section and isolated with 13-3/8" surface casing. A 12-1/4" hole was drilled across the loss zone and reactive shales formation keep the WBM weight as 9.4 ppg (70 PCF) while drilling the loss zone and increased later to 9.9 ppg (74 pcf) prior to drilling the reactive shale where the inclination was limited to 27 degree across it and built later to 32 deg at the end of 12 ¼" hole section and isolated with 9-5/8" production casing.8 ½" hole section was drilled with 12.3 ppg (92 pcf) OBM in order to built 82 deg before penetrating the reactive shale and hold it tangent to cover the maximum departure and built to 90 deg to land in target reservoir with total departure of 10,755 ft and isolated with 8,150 ft long 7" production liner, followed by 4,000 ft 6‘‘ horizontal open hole. This novel light casing design avoided drilling a hole section of 22‘’ and the associated 18-5/8" casing, saving at least 20 days in well duration and nearly $1 million in well cost. The new slim well design explained in this paper, which is used to drill long departure well with 10,000 ft, is the first of its kind in ADNOC Onshore field. It has proved that such long departure wells can be completed with light casing design and achieve 100% integrity.