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From a historic point of view, as jackup drilling vessels drilled in deeper water, the need to transfer the weight of the well to the seabed and provide a disconnect-and-reconnect capability became clearly beneficial. This series of hangers, called mudline suspension equipment, provides landing rings and shoulders to transfer the weight of each casing string to the conductor and the sea bed. Each mudline hanger landing shoulder and landing ring centralizes the hanger body, and establishes concentricity around the center line of the well. Concentricity is important when tying the well back to the surface. In addition, each hanger body stacks down relative to the previously installed hanger for washout efficiency.
Well preparation includes many activities to ensure that the well is completed properly. Some of these items and activities include appropriate drilling practices, cleanliness, completion fluids, perforating, perforation cleaning, acidizing, and/or specifications for rig and service company personnel. The productivity of a cased- or openhole gravel-packed completion is determined in part by the condition of the reservoir behind the filter cake, the quality of the filter cake, and the stability of the wellbore. Given this, it can be said that the completion begins when the bit enters the pay. Thus, it follows that the goal of drilling is to maintain wellbore stability while minimizing formation damage. But, for whatever reason, instability affects both cased- and openhole completions because it can cause loss of the wellbore. Thick cement sheaths in washed-out sections result in poor to no perforation penetration and the lack of cement can make sand placement difficult. Hole collapse can prevent running screens to the bottom of the hole. Failure, in the form of fracturing or collapse, can stop an openhole gravel pack, should failure occur while the pack is in process.
Elhassan, Azza (ADNOC Offshore) | Hamidzada, Ahmedagha Eldaniz (ADNOC Offshore) | Takahiro, Toki (ADNOC Offshore) | Motohiro, Toma (ADNOC Offshore) | Orfali, Mohd Waheed (Schlumberger) | Phyoe, Thein Zaw (Schlumberger) | Salazar, Jose (Schlumberger) | Alaleeli, Ahmed Rashed (ADNOC Offshore)
Abstract Good cementing practices are required to achieve effective zonal isolation and provide long-term well integrity for uninterrupted safe production and subsequent abandonment. Zonal isolation can be attained by paying close attention to optimizing the drilling parameters, hole cleaning, fluid design, cement placement, and monitoring. In challenging extended reach wells in the UAE, different methods were employed to deliver progressive improvement in zonal isolation. Cementing the intermediate and production sections in the UAE field is challenging because of the highly deviated, long, open holes; use of nonaqueous fluids (NAFs); and the persistent problem of lost circulation. Compounding the problem are the multiple potential reservoirs; the pressure testing of the casing at high pressures after cement is set; and the change in downhole pressures and temperatures during production phases, which results in additional stresses. Hence, the mechanical properties for cement systems must be customized to withstand the downhole stresses. The requirement of spacer fluids with nonaqueous compatible properties adds complexity. Lessons learned from prior operations were applied sequentially to produce fit-for-purpose solutions in the UAE field. Standard cement practices were taken as a starting point, and subsequent changes were introduced to overcome specific challenges. These challenges included deeper 12 ¼-in. sections, which made it difficult to manage equivalent circulating densities (ECDs), and a stricter requirement of zonal isolation across sublayers in addition to required top of cement at surface. To satisfy these requirements, several measures were taken gradually: applying engineered trimodal blend systems to remain under ECD limits; pumping a lower-viscosity fluid ahead of the spacer; using NAF-compatible spacers for effective mud removal; employing flexible cement systems to withstand downhole stresses; and modeling the cement job with an advanced cement placement software to simulate displacement rates, bottomhole circulating temperatures, centralizer placement, mud removal and comply with a zero discharge policy that restricts the extra slurry volume to reach surface. To enhance conventional chemistry-based mud cleaning, an engineered scrubbing additive was included in the spacers with a microemulsion-based surfactant. The results of cement jobs were analyzed by playback in advanced evaluation software to verify the efficiency of the applied solutions. This continuous improvement response to changes in well design has resulted in a significant positive change in cement bond logs; a flexural attenuation measurement tool has been used to evaluate the lightweight slurry quality behind the casing, which has helped in enhancing the confidence level in well integrity in these challenging wells. The results highlight the benefit of developing engineering solutions that can be adapted to respond to radical changes in conditions or requirements.
Abstract Today every Oil & Gas company is searching for the elusive drilling optimization process. Authors argue that a global drilling optimization is only achieved calculating the actual ROI – based on money spent in drilling vs total production of the well. As this is impractical, this paper presents a framework to measure engineering and management aspects of this optimization. Engineering approach looks into "doing things right," while managerial attitude is "doing the right things." Drilling optimization is centered in using existing (and upcoming) data from rig and its analyses. Engineers look into hydraulics, WOB, etc., with the purpose to calculate ideal/best ROP parameters and eventually to avoid problems, such as stuck pipe. This is done by direct calculation and/or running simulated models to spot deviations. Management is concerned with relative efficiency of the process (KPIs) compared to a baseline (offset wells, planned durations, technical limits, etc.). They concentrate at comparisons and focus at how to mitigate operational risks (time, costs, HSE, etc.) while producing the "best well". Those two intertwined optimization processes are depicted and explained in the next sessions. Authors' experience has shown that TL (Technical Limit), ILT (Invisible Lost Time) and NPT (Non-Productive time) are façades from the engineering and management efforts in drilling optimization. For example, there is no unique way to describe "Technical Limit" in drilling. We will describe the technical components for it under physics and models, as well as under historical-coaching-KPI approach. Same for ILT and NPT. Under a unique framework, users can understand and clarify the confusion in the current marketplace to better data and data processing to achieve optimization. The so called "data analytics" is dissected and formalized so all parties involved: technicians, service providers, operators, equipment suppliers, managers, finances, etc., can fully understand where data can be used (also how they are collected and quality checked) and what processes are needed to achieve each step of the drilling optimization. Unlike any product or service available today, the framework described in this article looks in the drilling optimization with a holistic view. Efforts so far have been scattered and there is a lack of an overall framework. The best results come from the combination of those two approaches.
Goodkey, Brennanl (Schlumberger) | Carvalho, Rafael (Schlumberger) | Nunez Davila, Andres (Schlumberger) | Hernandez, Gerardo (Schlumberger) | Corona, Mauricio (Schlumberger) | Atriby, Kamal (Schlumberger) | Herrera, Carlos (Schlumberger)
Abstract As margins tighten, players in the modern O&G landscape are being forced to reimagine their business models and re-evaluate their strategic direction to maintain a competitive edge. This often means doing more with less and spreading ever slimmer margins across increasingly complex well operations. Fortunately, with the wave of digital innovations that are sweeping the industry, most E&P organizations have a wealth of opportunities to streamline activity and increase efficiency while reducing the resources required. However, with the increasing array of digital opportunities, the gauntlet is set: those who adopt quickly and reap early benefits will undoubtedly be tomorrow's leaders. Laggards slow to adapt will fall progressively further behind as leaders successfully navigate through the learning phase and accelerate into new standards of efficiency. This combination of urgency and opportunity will undoubtedly be the force that propels the industry into the fourth great revolution; digital transformation. As observed in a variety of industries, automation has proven to be one of these instrumental digital levers to unlocking the next level of efficiency. Across the O&G industry, we are beginning to see a number of applications in which tasks are not only becoming less labor-intensive but also faster, safer and with increased levels of precision. This ensures that repetitive tasks which often drain and distract workers are re-allocated to automated processes while ensuring that employees remain concentrated on prioritizing safety and operations integrity. The value proposition for automation in drilling is especially compelling as human operators can easily become overwhelmed with the volume of competing priorities and the pressure to make immediate decisions. By carefully delegating some of the decision-making to an intelligent drilling system, the cognitive burden on human operators is reduced resulting in a safer working environment conducive to increased performance and engagement. In this paper, a detailed case study is presented to document the effort of a major service company to deploy a full drilling automation system in the Middle East implemented to autonomously operate rig surface equipment. A detailed description of the system's intelligent management system will be provided to communicate its capacity to interpret and autonomously respond to changing well conditions. A case study approach will be used in attempt to specifically identify the areas where automation delivers a step change in results compared to manual operations. Additionally, given the complexity inherent to executing a digitalization project in drilling, insight will be shared on the strategies leveraged to navigate the intricacies of deployment and adoption. Throughout this paper, it will become evident that automation is quickly becoming a reliable solution for the consistent delivery of top quartile performance by unlocking new levels of consistency and procedural adherence.
Kuyken, Chris Wilhelm (AlMansoori Specialized Engineering) | Elkasrawy, Mohamed Elsaied (AlMansoori Specialized Engineering) | Al Breiki, Ali Mubarak Saeed (ADNOC Onshore) | Elgendy, Yahia Abdelfattah Mahmoud (Schlumberger) | Abdelaal, Ahmed Gamal (AlMansoori Specialized Engineering)
Abstract High performance drilling is an approach applied in the drilling of hole sections that are not primarily benefitting from data acquisition except the minimum like gamma ray and directional. Therefore these sections are drilled with high ROP and subsequently cased in support of reducing well costs. High performance drilling leading to continuous ROP optimization has been proven a key enabler for invisible lost time reduction (ILT), being one of the current regional well delivery challenges. In this paper we explain the approach followed by the team comprising of operator, service provider and equipment provider in reducing the impact of ILT during the actual drilling phase. We learnt that creating a performance culture based on rigorously applying of best practices and the eagerness to continuously improve on past performance as a first strategy and the application of novel directional drilling motor technology as the second resulted in ROP performance records. For example in one field an average ROP record was achieved of 188 ft / hour a 15 % improvement from the previous record. We learnt that in particular the communication between all parties i.e. the client office, the service provider and the team on the rig was the most important factor in order to create a shared vision on the need to improve the ROP based on the last ROP performance benchmark. Secondly the latest motor technology and the way of how it gets deployed, available to the team played a major role, and brought the performance level to a new dimension whereby the ROP was targeted to be optimum instead of maximum thereby reducing the risk for NPT related incidents (hole problems, equipment break-down) and repair and maintenance cost becoming cost prohibitive. This paper is specifically meant to share best practices from the last 10 years with the larger UAE drilling community. It is service provider contribution to provide insights for the new generation drilling engineers and directional drillers in safely pushing the drilling performance to higher levels all the time targeting the ILT in hole making. The work has proved that a combination of low torque high speed and high torque low speed can successfully performance drill all vertical hole sizes in the UAE on-shore fields either using tri-cone or PDC bits.Figure 1: High performance motor
Abstract Aiming to make the well planning process leaner and agile focusing on duration reduction without compromising quality of deliverables, automation opportunities have been identified within the multi-discipline iterations. The two key criteria considered for the selection of the automation project were: Minimum deployment effort and Maximum value added in efficiency. The initial project objective was to calculate formation tops for a well engineer without requiring the intervention of a geoscientist using commercial software. The methodology utilized is the following: 1. Inputs: Well trajectory and Surfaces. 2. Process: The algorithm finds intersections between surfaces and well trajectory. Surfaces and trajectory are represented as a set of XYZ points. To find the intersection, the software iterates through each point of the trajectory from the top, comparing the depth of the projection to the target surface. The projected depth to the surface is found by 2D interpolation of the surface. Once the trajectory point becomes deeper than the surface projection, the intersection is estimated using geometrical considerations of similar triangles. 3. Deliverables: Estimated formation tops for the given trajectory. 4. Results: Simple in-house developed software enhanced well planning workflow in an Offshore Green Field. The software converted to single executable file and can be run on any device without the open-source software installed. Very accurate results achieved with proposed algorithm with a negligible difference of 0.5 feet with the geoscience traditional software. Well planning duration reduced from average 1 week to 1 or 2 days. The workload for well engineers and the asset team has been dramatically reduced. Reduction of the number of commercial geoscience software licenses required. Way forward: A test with a slightly modified code was used to generate formation tops for more than 400 well in a Long-Term Field Development Plan project for a Brown Field during feasibility study. Upscale to all the Fields within the organization. Improve User Interface for better adoption. Include more formats for both, trajectories, and surfaces. Reduce computing time. This project represents the first initiative in the organization aiming to automate the well planning process. Overall, it represents the beginning of a journey where multiple opportunities for automation can be achieved using an open-source coding software that allows any engineer with little to no experience coding to being able to generate solutions to address daily challenges.
Samuel, Orient Balbir (PETRONAS Carigali Sdn. Bhd.) | Chandrakant, Ashvin Avalani (PETRONAS Carigali Sdn. Bhd.) | Salleh, Fairus Azwardy (PETRONAS Carigali Sdn. Bhd.) | Jamil, Ahsan (Baker Hughes) | Ibrahim, Zulkifli (Baker Hughes) | Ivey, Alan (Baker Hughes)
Abstract Field D is a mature offshore field located in East Malaysia. A geologically complex field having multiple-stacked reservoirs with lateral and vertical faulted compartments & uncertainty in reservoir connectivity posed a great challenge to improve recovery from the field. Severe pressure depletion below bubble point and unconstrained production from gas cap had contributed to premature shut-ins of more than 50% of strings. As of Dec 2019, the field has produced at a RF less than 20%. Initial wells design consisted of conventional dual strings & straddle packers with sliding sleeves (SSD). Field development team was challenged for a revamp on completion design to enhance economic life of the depleting field. In 2015, as part of Phase-1 development campaign, nine wells including four water injectors were completed initiating secondary recovery through water flood. An approach of Smart completion comprising of permanent downhole monitoring system (PDHMS) and hydraulic controlled downhole chokes or commonly known as flow control valve (FCV) was adopted in all the wells in order to optimize recovery from the field and step towards intervention-less solutions. Seeing the benefits of intelligent completion in Phase-1, Phase-2, drilled and completed in 2019 – 2020 has been equipped with new technology "All-electric Intelligent Completion System" in 4 out of 8 oil producers. The new design addresses the reservoir complexity, formation pressure and production challenges and substantial cost optimization, phasing out the load of high OPEX to CAPEX. Installation of "All-electric Intelligent Completion System" has proven to be an efficient system compared to hydraulic smart completions system. It requires 50% to 75% less installation time per zone and downhole FCV shifting time is less than five minutes compared to several hours full cycle for hydraulic system. The new system has capability to complete up to 27 zones per well with single cable. It gave more options and flexibility in order to selectively complete more zones compared to hydraulic FCVs which requires individual control line for each zone. Future behind casing opportunities (BCO) have been addressed upfront, saving millions of future investment on rig-less intervention. In addition to that, non-associated gas (NAG) zones have been completed to initiate in-situ gaslift as and when required avoiding the dependency on aging gaslift facility. The scope of the paper is to show case the well design evolution during Field D development and highlight on how smart completion has evolved from original dual completion to hydraulic smart and recently to electric smart system, how it has contributed to cost and production optimization during installation and production life and also support the gradual digitalization of the Field D. In the end it demonstrates the optimized completion design to enhance the overall economic life of the depleting field.
Abstract The present paper describes the results of the formulation of an acid-soluble low ECD organoclay-free invert emulsion drilling fluid formulated with acid soluble manganese tetroxide and a specially designed bridging package. The paper also presents a short summary of field applications to date. The novel, non-damaging fluid has superior rheology resulting in lower ECD, excellent suspension properties for effective hole cleaning and barite-sag resistance while also reducing the risk of stuck pipe in high over balance applications. 95pcf high performance invert emulsion fluid (HPIEF) was formulated using an engineered bridging package comprising of acid-soluble bridging agents and an acid-soluble weighting agent viz. manganese tetroxide. The paper describes the filtration and rheological properties of the HPIEF after hot rolling at 300F. Different tests such as contamination testing, sag-factor analysis, high temperature-high pressure rheology measurements and filter-cake breaking studies at 300F were performed on the HPIEF. The 95pcf fluid was also subjected to particle plugging experiments to determine the invasion characteristics and the non-damaging nature of the fluids. The 95pcf HPIEF exhibited optimal filtration properties at high overbalance conditions. The low PV values and rheological profile support low ECDs while drilling. The static aging tests performed on the 95pcf HPIEF resulted in a sag factor of less than 0.53, qualifying the inherent stability for expected downhole conditions. The HPIEF demonstrated resilience to contamination testing with negligible change in properties. Filter-cake breaking experiments performed using a specially designed breaker fluid system gave high filter-cake breaking efficiency. Return permeability studies were performed with the HPIEF against synthetic core material, results of which confirmed the non-damaging design of the fluid. The paper thus demonstrates the superior performance of the HPIEF in achieving the desired lab and field performance.
Kumar, Shailesh (Indian Institute of Petroleum and Energy) | Rajput, Vikrant Singh (Oil and Natural Gas Corporation Limited) | Mahto, Vikas (Indian Institute of Technology (Indian School of Mines) (Corresponding author)
Summary The development of concentrated and highly stable oil-in-water (O/W) emulsion is considered to be a cost-effective alternative for the transportation of produced heavy crude oils. However, the demulsification of a transported O/W emulsion is necessary once it reaches the destination. This article experimentally investigates the performance of four low-cost chemicals of varying water solubility as potential demulsifiers, independently and in combinations, for demulsifying two Indian heavy crude O/W emulsions prepared for pipeline transportation. The chemical demulsifiers used, in order of their higher water solubility, are: polyethylene glycol 400 (PEG) > polyoxyethylene (20) sorbitan monooleate (Tween-80) > linear alkylbenzene sulfonic acid (LABSA) > n-octylamine (OA). For this study, stable O/W emulsions (in the 60:40 ratio) of two Indian heavy crude oils were prepared using high-frequency ultrasonic waves in the presence of Triton X-100 as a surfactant. Both crude oils were characterized at first based on their physicochemical properties, infrared (IR) spectrum, and rheological properties. Prepared O/W emulsions were characterized based on rheological properties and droplet size. A bottle test method with heating (using a water bath) and enhanced gravity (by centrifuge) has been used to study the demulsification efficiency of used chemicals. Complete demulsification of both emulsions was achieved as desired. The synergetic effect of the interaction between two suitable demulsifiers provided remarkably better performance than that of independent returns, leading to minimization of the amount of demulsifier and the energy requirement for complete demulsification of both emulsions.