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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.
Traboulay, Vaughn Reza (Schlumberger) | Aung, Tint Htoo (Schlumberger) | Manzoleloua, Cedric (Schlumberger) | Panamarathupalayam, Balakrishnan (Schlumberger) | Arena, Carmelo (Schlumberger) | DMello, Allwyn (Schlumberger) | Sebelin, Linus (Schlumberger) | Eyaa, Clotaire (Schlumberger)
Abstract High-temperature water-based drilling fluid systems hold several advantages over synthetic based systems from financial and environmental viewpoints. However, most conventional water-based systems start to become unstable at temperatures above 300 degF. This paper details the design and implementation of A Novel Water-Based Drilling Fluid that meet these temperature stability requirements. The newly developed high-temperature water-based system discussed in this paper utilizes a custom-made branched synthetic polymer that exhibits superior rheological properties and fluid loss control as well as long term stability above 400 degF. The branched synthetic polymer is compatible with most oilfield brines and maintains excellent low-end rheology necessary for hole cleaning and solids suspension under high-temperatures and pressures. Under static conditions, the high-temperature fluid shows no gelation resulting in lower swab surge pressures while the stability of the highly branched synthetic polymer and enhanced rheological profile minimize sag. To drill a challenging exploration well, a Middle East client required a cost-effective drilling fluid system which remains stable under static temperatures expected to exceed 375 degF. The long-term stability of the system was critical for successful wireline logging operations. In addition, the system was required to provide shale inhibition, hydrogen sulfide suppression and sufficient density (above 16.5 lbm/galUS) to maintain well integrity while drilling through anticipated high-pressure zones. The challenging intermediate (12.25-in and 8.375-in) and reservoir (6-in) sections were successfully drilled and evaluated using this new branched synthetic polymer-based system. Fluid property trends and system treatments will be detailed alongside thermal stability data for extended periods required for wireline logging (up to 9 days static). This paper will discuss how proper laboratory design of the high-temperature water-based system was translated to excellent field performance and will indicate how this technology can be utilized for future campaigns in the region and worldwide.
Abstract A new valve has been designed and qualified to reduce interventions during packer-setting operations. In a typical well, completion with a hydraulic-production packer, the tubing string must be plugged to create the required pressure differential for packer actuation. At desired depth, delivering a preselected circulation rate actuates the tool and converts the string to a closed system, enabling the packer to be set hydraulically. Before designing the valve, an operator's engineering and operational requirements were collected and understood. Then a conceptual design was evaluated, and a prototype device was manufactured. The valve was tested for autofill capability, actuation parameters and pressure integrity. The critical design elements of the valve are the choking and spring mechanisms, which enable circulation without prematurely actuating the valve and then enable tubing autofill. A visual inspection post qualification test was conducted to validate the components’ condition and integrity. During the qualification process, the valve working envelope was developed. After the successful qualification test, the valve was deployed in a customer well with a production packer that has a blanking device consisting of a ceramic disc. Prior to deployment, hydraulic simulation was done to determine the required flow rate to achieve desired pressure drop across the valve for actuation. During deployment, the tubing was filled automatically, validating the valve autofill capability. Upon reaching setting depth, the completion string was circulated at the required circulation rate to actuate the valve and close the system. Pressure integrity in the tubing validated the valve functionality. Surface pressure was applied against the blanking device, and the production packer was set hydraulically. Subsequently, before completing the well, the blanking device was broken using a slickline run, and the well was put on production. The deployment technique using the valve requires only one slickline run whereby in typical operation four slickline runs are required. This project represented true problem-solving engineering approaches. The operator requirements were properly understood and conceptual design was validated, and product realization phase was initiated. The efficient product development methodology improves the lead time from conceptualization to product realization. During the first well deployment, hydraulic simulation during the prejob planning proved to be critical to understanding the required circulation rates to actuate the valve.
Abstract On a Deep Gas Field in the Middle East, it is required to drill across a highly fractured and faulted carbonate formation. In most wells drilled across the flank of this field, it is impossible to cure the encountered losses with conventional or engineered solutions. Average time to cure losses is 20 days. With the current drive for cost optimization, it has become necessary to eliminate the NPT associated with curing the losses. A thorough risk assessment was conducted for wells drilled on the flank of this field, it was established that the risk of encountering total losses was very high. Seismic studies were performed and it was observed it would be impossible to eliminate total losses as fractures were propagated in all directions. It was proposed to run a sacrificial open hole bridge plug above the loss zone and sidetrack the well instead of performing extensive remedial operations. The proposed solution would help eliminate the well control and HSE risks associated with drilling blindly ahead with the reservoir formation exposed. Applied the proposed solution on the next well that was drilled on the flank of the field, encountered total losses, spotted eight LCM pills, unable to cure the losses, ran sacrificial open hole bridge plug and sidetracked the well. The entire process was completed in 30 hours. Sidetracked the well in adjacent direction to the initial planned well trajectory based on further seismic data analysis and no losses was encountered. Recovered full mud column to surface thus ensuring the restoration of all well barrier elements. This solution has since been adopted as best practice for wells drilled on the flank of the field where there is high probability of encountering total losses. The average time saving per well due to this optimized solution is 450 hours for wells where total losses are encountered. This engineered solution has made drilling wells on the flank of the field in a timely manner possible and at optimized costs. This has resulted in: –The elimination of Non-Productive Time, –Quick delivery of the well to production, –Reduced HSE risk, –Reduced well control risk as loss zone is quickly isolated before drilling ahead. This paper will explain why running sacrificial open hole bridge plugs and sidetracking the well is a more effective solution compared to extended remedial operations when total losses are encountered while drilling across highly fractured / faulted formation. It will discuss the extensive risk assessment conducted, the mitigation and prevention measures that were put in place in order to ensure successful implementation on trial well.
Abstract On a Deep Gas Project in the Middle East, it is required to drill 3500 ft of 8-3/8" deviated section and land the well across highly interbedded and abrasive sandstone formations with compressive strength of 15 - 35 kpsi. While drilling this section, the drill string was constantly stalling and as such could not optimize drilling parameters. Due to the resulting low ROP, it was necessary to optimize the Drill string in order to enhance performance. Performed dynamic BHA modelling which showed current drill string was not optimized for drilling long curved sections. Simulation showed high buckling levels across the 4" drill pipe and not all the weight applied on surface was transmitted to the bit. The drilling torque, flowrate and standpipe pressures were limited by the 4" drill pipe. This impacted the ROP and overall drilling performance. Proposed to replace the 4" drill pipe with 5-1/2" drill pipe. Ran the simulations and the model predicted improved drill string stability, better transmission of weights to the bit and increased ROP. One well was assigned for the implementation. Ran the optimized BHA solution, able to apply the maximum surface weight on bit recommended by the bit manufacturer, while drilling did not observe string stalling or erratic torque. There was also low levels of shocks and vibrations and stick-slip. Doubled the on-bottom ROP while drilling this section with the same bit. Unlike wells drilled with the previous BHA, on this run, observed high BHA stability while drilling, hole was in great shape while POOH to the shoe after drilling the section, there were no tight spots recorded while tripping and this resulted in the elimination of the planned wiper trip. Decision taken to perform open hole logging operation on cable and subsequently run 7-in liner without performing a reaming trip. This BHA has been adopted on the Project and subsequent wells drilled with this single string showed similar performance. This solution has led to average savings of approximately 120 hours per well drilled subsequently on this field. This consist of 80 hours due to improved ROP, 10 hrs due to the elimination of wiper trip and a further 30 hrs from optimized logging operation on cable. In addition, wells are now delivered earlier due to this innovative solution. This paper will show how simple changes in drill string design can lead to huge savings in this current climate where there is a constant push for reduction in well times, well costs and improved well delivery. It will explain the step-by-step process that was followed prior to implementing this innovative solution.
Obeid, Ahmad Fayyad (Adnoc Offshore) | Bespalov, Eugene (Schlumberger) | Sanghavi, Dharam (Schlumberger) | Almasri, Ahmad (Schlumberger) | Magri, Jose (Schlumberger) | Al Hammadi, Majid Ismail (Adnoc Offshore) | Al Marzooqi, A. M. (Adnoc Offshore) | Yoshimoto, Kazuhito Kazumi (Adnoc Offshore) | Yamashita, Hajime (Adnoc Offshore) | Al Zaabi, Ali Yousef (Adnoc Offshore)
Abstract Electric submersible pumps (ESPs) used as an artificial lift method have a relatively short life span despite the industry's efforts to improve reliability. The resulting economic impact realized in workover costs and production loss is substantial. This has driven efforts toward design change by introducing retrievable ESP independent of the completion string and hence extending ESP wells’ life cycle. This paper covers the company's first installation of a rigless shuttle ESP system, including a customized completion design and special deployment procedures. A comprehensive approach was taken to deploy this technology, from procurement to installation, in a detailed process. It started with acquiring reservoir data and setting up matching specifications for the required equipment in order to issue a competitive tender. Following technical evaluation of tender submissions, the most suitable technology was selected for the field trial. The completion design was then customized to accommodate the new technology without jeopardizing well integrity. Fit-for-purpose well barriers were incorporated in the completion design because conventional barriers were not applicable. Detailed running procedures were produced from dedicated workshops and risk assessment reviews. Project execution was closely monitored and firmly controlled. The company has accomplished the first successful offshore deployment of the shuttle ESP system in the MENA region. The system was deployed using tailored procedures for installation and comprehensive testing while ensuring compliance with well barrier requirements. Following successful deployment, the ESP performance was positively tested. Part of the project validation requirement was a rigless retrieval and redeployment the ESP system. The ESP retrieval process was challenging due to unexpected tar or asphaltene material encountered above the ESP. However, contingency retrieval procedures were promptly amended with detailed steps to overcome this challenge, which led to successful retrieval and redeployment of the ESP without NPT. This success is paving the way for a major change in the company's field development strategies by considering rigless, replaceable ESP systems instead of the conventional ESPs. This paper sheds the light on a new advancement in completion technology that has a strong potential to prevail for ESP-lifted wells in the future. The focus of the paper is on the design and execution parts, as well as installation and post-completion operations while maintaining sufficient well barriers―the challenging aspect that appears to be slowing down the wider use of this technology as a replacement of conventional ESP completions.
Haddad, Mohamed (ADNOC Offshore) | Alwahedi, Khalid Ahmed (ADNOC Offshore) | Al Hilali, Osama Mohamed (ADNOC Offshore) | Cesetti, Maurizio (ADNOC Offshore) | Benygzer, Mhammed (ADNOC Offshore) | Husien, Mohammad (ADNOC Offshore) | Allogo, Clotaire-Marie Eyaa (Schlumberger) | Cholakkaparamban, Naseerali (Schlumberger) | Barcan, Armand (Schlumberger) | Rasheed, Ami (Schlumberger)
Abstract The paper will present lessons learnt to mitigate the stabilization of the air/gas entering into lubricious biopolymer water-based system which decreased density of mud while drilling. The system selected for its highly lubricious properties and formation damage free properties to accommodate the usage of resistivity equipment provided excellent results in the field. Performance was almost equivalent to non-aqueous drilling fluid. However, the stabilization of gas/air entering the mud was encountered generating drilling troubles and risk of well control problems. An extensive study performed, consisted of assessing interactions between components and containments of the mud system with gas/air, crude-oil and drill solids introduced from the reservoir. The testing involved the adding of air from air-compressor for 60-second while mud sample is sheared at 6000 rpm. The mud weights of samples were measured before addition of air, right after and 60-second after the aeration. The percentage of density drop was calculated. Target value was maximum drop of 5% within 60 second after stopping the addition of air. Several combinations of polymers, lubricants, contaminants and other additives were evaluated. The study demonstrated that the interactions between crude-oil, polymers and lubricants can highly stabilize air/gas entrapment in the biopolymer water base mud system. The phenomena led to significant density decrease, drilling troubles, well control and safety issue in the field. They can also increase the viscosity of the biopolymer mud system. However, highly stabilized air/gas entrapment can be removed by the addition of emulsion breaker at concentration less than 1.5%vol of mud. In addition, the type and nature of the lubricant plays a major role in the stabilization of air/gas entrapment. The selection of the polymers should be combined with the choice of lubricant during the design phase to minimize the gas entrapment. Knowledge gained from the study establish a new testing protocol to assess in the laboratory the air/gas entrapment close to field shear conditions. The testing protocol showed good correlation with the field. The testing protocol can be used during the design phase or for investigations. It will improve the overall design of mud system where highly lubricious fluid is needed. Combination of polymers and lubricants did also provide low air/gas entrapment tendency.
Abstract Drilling horizontal wells with a high dogleg severity (DLS) of 10–16 deg/30 m is the approach that one operator in Oman adopted to drill the buildup section. The 8½-in section used to be drilled with a conventional motor BHA, which took around 4 days to complete. Due to the high DLS, it was required to slide at least 80% of the time. This led to a slow drilling rate, hole cleaning issues, and difficulties running the 7-in liner afterward. For a step change to happen, a full directional drilling system had to be reengineered with an extensive study of the BHA and well design. The objective was to reduce the total drilling time in the 8½-in BUS, improve the borehole quality, and reduce flat time. Traditional rotary steerable systems (RSS) are limited with their steering capabilities. A hybrid, high-build-rate RSS with push- and point-the-bit features offers the capabilities of achieving a DLS of up to 17 deg/30 m as it is independent of outside formation. Implementing the new approach eliminated the long sliding intervals and poor borehole cleaning caused by limited surface rotation with the motor BHA. The system was modeled using finite element drilling dynamics simulation software, with multiple bits and drillstring configurations to optimize the directional results. In addition, compressive study of the mud properties enabled drilling the section safely throughout Nahr Umar shale. Later, the same system was coupled with a high-torque motor, and the results showed an even better performance, which the operator plans to consider in the future to enhance the drilling rate. The use of a hybrid RSS system with a specific bit built for the application has proven its success as an integrated engineered drilling solution. It reduced the 8½-in section drilling time by 50% with improved borehole quality and delivered an overall ROP that is approximately three times what a motor BHA would have delivered. The improvement is a result of the use of PDC over TCI bits and the elimination of slide drilling. In addition, full rotation and elimination of micro-DLS resulted in smoother liner running operation. While drilling, the 100% rotational steering improved the overall hole cleaning, and the modified mud properties and additives helped eliminate the wiper trips performed previously prior to reaching the reservoir section. The success of this integrated system led the operator to replace all the motors in the entire field. This paper emphasizes the impact of new technology together with effective well engineering in drilling efficiency. With current industry focus on cost control, high-DLS RSS technology introduces new savings when used in the right application. This particular case is very common across the industry and proves the many advantages of integrated engineering projects.
Krikor, Ara (Schlumberger) | Sanderson, Martin (Schlumberger) | Merino, Lizeth (Schlumberger) | Benny, Praveen (Schlumberger) | Ibrahim, Sameh (Schlumberger) | Al-Khayat, Khaled (Schlumberger) | AlYasiri, Siffien (Schlumberger)
Abstract Drilling highly intercalated formations with Polycrystalline Diamond Compact (PDC) bits has been a challenge in few Southern Iraqi Fields. The established drilling practice for the 17.5-in section has been a two-run strategy - Top section formation is mostly dolomite intercalated with anhydrite drilled with a Tungsten Carbide Insert (TCI) bit, then trip out of hole to change to a PDC bit and drill to section TD. The upper section comprises highly intercalated formations known to induce severe bit and BHA damage. The application of new Conical Diamond Elements (CDEs) backing up traditional PDC cutters on the bit blades had significantly improved bit durability in the bottom half of the section. The subsequent challenge was to apply this CDE technology onto an optimized PDC chassis and achieve a single run section thus eliminating a trip for bit change as well as improving overall Rate of Penetration (ROP) of the section. A Bit and drill string optimization exercise was initiated by the Technology Integration Center to develop a new PDC bit design that could deliver a shoe-to-shoe section. Analysis of offset well data highlighted the need for greater cutter redundancy on the bit to survive high impact loading and optimized cutter arrangement to minimize bit induced instability while drilling through intercalations with highly fluctuating rock strengths. A finite element analysis (FEA)-based modelling system was used to evaluate the dynamic behavior of multiple bit design configurations in various rock scenarios and narrow down to the optimum design for the challenge. The optimization exercise shortlisted a PDC bit design characterized by 8 Blades, 16-mm PDC cutters and CDEs backing-up the nose and shoulder PDC cutting structure. A detailed drilling parameter road map was also generated to ensure optimum drilling parameter application for shoe-to-shoe assurance. The new bit drilled the entire section in single run with a field record average on-bottom ROP of 20 m/hr which was a 11% improvement over the best offset performance with a two-bit strategy. In addition, a trip for bit change was eliminated. A minimum saving of 20 rig hours was realized thus reducing section time by almost one day compared to the offset wells. The bit was pulled out of hole with minor cutter damage indicative of efficient drilling dynamics and opportunities for further performance enhancement through improved parameter management, alternate drive systems and high torque drill pipes. This paper further will discuss how the technology integration and precise engineering design can solve complicated on bottom drilling problems and address the problematic challenges of drilling highly intercalated formations. This strategy enabled a significant time and cost saving compared to drilling the section conventionally.
EL Helali, Osama (ADNOC OFFSHORE) | Haddad, Mohamed (ADNOC OFFSHORE) | Gumarov, Salamat (Schlumberger) | Benelkadi, Said (Schlumberger) | Bianco, Eduardo (Schlumberger) | Mitchel, Craig (Schlumberger)
Abstract Cuttings reinjection (CRI) project at OFFSHORE ABU DHABI field achieved successful operation with three million barrels injected to date with zero subsurface failures setting up an environmentally friendly and cost-effective waste management success story that complies with zero discharge requirements. The project exceeded initial expectations by accommodating non-aqueous drilling waste from jack-up drilling rigs in addition to artificial islands own rigs. Subsurface assurance and engineering workflows proved to be effective in ensuring subsurface containment of drilling waste in challenging environment while ensuring efficiency of operation to meet demanding drilling schedules. Injection schedules and procedures were based on results of thorough subsurface FEED study and global best practices. Slurry fluid quality requirements were verified thru extensive laboratory tests. Throughout injection operation downhole pressure and temperature of the injection well was vigilantly monitored and analyzed along with well temperature survey and periodic fracture modeling updates of the fracture waste domain to ensure seamless fracturing of formation and containment of waste domain within selected formation. More than 3 million barrels of drill cuttings and associated drilling waste have been safely and successfully disposed of into a single injection zone of two cuttings reinjection wells over five years of project operation to date. No downtime was experienced and no impact to drilling schedule was induced demonstrating high capability of technology when designed and executed in right way. Results of actual injections showed accuracy and robustness of the engineering workflow implemented from Job design, planning and execution The paper presents unique and knowledge-based steps that contributed to success of project and set high bar for region for the drilling waste management.