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Tropical storms severely affect oil and gas production in the Gulf of Mexico, especially during the storm season from June to December. Offshore well managers often need to shut down operations and evacuate the facility because of storm alerts. Furthermore, if the storms have a more-severe effect, facilities may need to be repaired before production restarts. The purpose of this paper is to determine the effect of storms on production by quantifying metrics such as downtime days and downtime percentage after the storm has passed and whether a facility's platform type affected these metrics. Oil and gas production at offshore facilities (Figure 1) are severely affected, especially in the Gulf of Mexico, by frequent storms.
Hamid, Mohd Ridzuan (PETRONAS Carigali Sdn Bhd) | Meor Hashim, Meor M. (PETRONAS Carigali Sdn Bhd) | Norhashimi, Lokman (PETRONAS Carigali Sdn Bhd) | Arriffin, Muhammad Faris (PETRONAS Carigali Sdn Bhd) | Mohamad, Azlan (PETRONAS Carigali Sdn Bhd)
Abstract The recent global pandemic is an unprecedented event and took the world by storm. The Movement Control Order (MCO) issued by Malaysia's government to halt the spread of the deadly infection has changed the landscape of work via a flexible working arrangement. The Wells Real Time Centre (WRTC) is not an exception and is also subjected to the change. WRTC is an in-house proactive monitoring hub, built to handle massive real-time drilling data, to support and guide wells delivery effectiveness and excellence. The functionality of the WRTC system and applications are embedded in the wells delivery workflow. The centre houses drilling specialists who are responsible for observing the smooth sailing of well construction and are tasked to intervene when necessary to avoid any unintended incidents. WRTC is equipped with myriads of engineering applications and drilling software that are vital for the operations. Such applications include monitoring software, machine learning applications, engineering modules, real-time data acquisition, and database management. These applications are mostly cloud-based and Internet-facing, hence it is accessible and agile as an infrastructure that is ready to be deployed anytime anywhere when it is required. The strategy for WRTC mobility started as soon as the MCO was announced. This announcement mandated the WRTC to operate outside of the office and required the staff to work from home. The careful coordination and preparation to transform and adapt WRTC to a new norm was greatly assisted by the infrastructure readiness. All of these factors contributed greatly to a successful arrangement with zero to minimal downtime where a workstation was set up in each personnel's home, running at full capacity. This transformation was done within one day of the notice and completed within hours of activation. Despite the successful move, few rooms for improvements such as redundancy of VPN use to access applications and limited access to some proprietary software can be enhanced in the future. WRTC is ready to be mobile and agile to support the drilling operations remotely either in the office or from home. The quick turnaround is a major indicator that WRTC infrastructure and personnel are ready and capable for remote operations without interruption.
Abstract Immiscible Water Alternating Gas (iWAG) scheme was adopted in Echo field, offshore Sarawak Malaysia, to increase recovery factor of the matured oil reservoir after more than two (2) decades of peripheral water injection. It was implemented through four (4) horizontal wells located at reservoir’s eastern and western flanks. Since the commencement of iWAG injection, multiple challenges occured interrupting the stable injection that halting the success of this integrated mega scale project. It started with prolonged iWAG performance test run due to surface constraint, measurement and well issues on executing switching test, followed with low injectivity during switching operation. Subsequently, injectivity issues occured in the gas phase after several injection cycles. In addition to that, injector wells facing high downtime due to surface facilities and well integrity issues, causing low injection rates and unavailability to meet cycle volume within the stipulated duration. Reactivation of iWAG benefiter wells also prove to be challenging due to wells have been idle for a long time and multiple interventions required to revive the well. Injection data for both gas and water phase were analysed to improve iWAG operating procedure and understand the wells performance. INJ-J2 was installed with temporary pressure gauge during the water to gas switching, while the other two (2) wells are equipped with Permanent Downhole Gauge (PDG) to monitor the well injectivity. Application of non-intrusive flowmeter was also proven useful in calibrating the Flow Transmitter (FT) for both water and gas injectors, ensuring the accuracy and precision in the water and gas injection measurement. Besides that, fluid temperature trending was referred to validate on the meter measurement. Low injection rate compared to original plan were reviewed with the Reservoir Management Plan (RMP). Several approaches are implemented in order to achieve the iWAG RMP target and idle well reactivation. Analysis of injection data showed that gas injectivity issue occurred after the water to gas switching cycle. Injectivity improves slightly after long duration of continuous gas injection and applying higher Tubing Head Pressure (THP), unfortunately some wells remain with low injectivity because of insufficient discharge pressure to push the water from the near-wellbore deep into the reservoir to improve injection. Low injection rate issue is mitigated by extending injection cycle duration in order to meet the RMP cycle volume. Besides that, wells are normally injected with higher injection rate to cater for the high downtime. Both gas and water injection are balanced to ensure that the wells reached their cycle volume at similar duration. With limited new field discovery by the Operator, tertiary recovery on the mature field is inevitable. However, there is less implementation of iWAG in offshore field. Through this paper, authors wish to provide insights and lesson learnt for others when planning for iWAG tertiary recovery, taking account of various challenges faced.
There is a limit to disruptive innovation in oilfield technology. Blowout preventers (BOP) show how hard it can be. A decade ago on 20 April 2020, the Macondo disaster made a powerful case for change when this last line of defense failed to stop a blowout that caused explosions and a fire that killed 11, destroyed the Deepwater Horizon drilling rig, and set off one of the largest oil spills ever in the Gulf of Mexico. Scathing reports from investigations and staggering payouts from lawsuits against BP and other companies highlighted the shortcomings of machines that failed to serve as the last line of defense when natural gas surged onto the drilling floor, setting off a series of explosions. The investigations highlighted a long string of errors that led to the avoidable crisis. There was a failure to verify the cementing, missed signs of gas building up in the well, and a delayed decision to activate the BOP until the explosions already may have severed the hydraulic lines to the wellhead. But the simple explanation for it all: The shear rams failed to sever the pipe and seal the well.
Schlumberger will be shedding its fracturing services operations in a deal with Liberty Oilfield Services in exchange for 37% of that company's stock. For the giant oilfield services company, the OneStim deal eliminates a line of business in a deep slump which has been a major reason for losses in its North American business. Those losses have offset profits from its international operations. For Liberty, the all-stock deal doubles its working pressure-pumping capacity without adding any debt to the balance sheet of a company that avoids borrowing, making this the rare shale-industry merger that is welcomed by investors. Liberty shares were up more than 35% in 1 September afternoon trading, while Schlumberger was off by 1.4%.
Past experiences with problematic situations often drive the decision-making process, and while experience may be helpful, it can also lead to the development of biases that hamper an organization's ability to manage dynamic environments such as unconventional projects. As unconventionals have grown in complexity, the effects of critical errors on safety and production have grown in magnitude. In order to have a strong error management system, companies must emphasize situational awareness in their operations, an expert said. In a presentation held at the Unconventional Resources Technology Conference in San Antonio, Wayne Jackson discussed how a focus on situational awareness can help operators improve on-site safety and operational efficiency. Jackson is president of Cougarstone Solutions, a technology company based in Calgary.
Some offshore drillers and equipment makers are betting that a cooperative, long-term relationship will reduce the cost of deepwater well control equipment. Contracts signed over the past the past year by Diamond Offshore Drilling and Transocean, covering a total of 20 offshore drilling units, give GE Oil & Gas and Schlumberger more responsibility, and some risk, for maintaining well control equipment. Intense pressure to both reduce costs and improve reliability and safety is pushing drillers and equipment makers to change. "The unit of measure on this is definitely not hours, days, weeks, or months," said Chuck Chauviere, president of Drilling Systems for GE Oil & Gas. "It is more accurately charted against quarters and years."
Kuwait Oil Company started free gas production from its Jurassic sour-gas field in May 2008 with the commissioning of Early Production Facility (EPF) 50. The well fluid is characterized by high hydrogen sulfide (H2S) (5%) and carbon dioxide (CO2) (5%) content. Handling such highly corrosive well fluid creates a wide range of challenges, from upstream at the wellhead to downstream at the processing facility. Upstream challenges for the Jurassic gas field have been related mostly to subsurface corrosion of tubing, unplanned well downtime because of hydrate formation during winter, and failure of automated chokes for some wells. A moderate to severe corrosion rate has been indicated by corrosion logs in the production tubing because of the high H2S and CO2 content of the well fluid.
DNV GL proposes the Probabilistic Digital Twin (PDT) to close the gap between digital twins--used increasingly by operators to manage the performance of their assets--and risk analysis still largely conducted manually before assets enter service. A digital twin is a digital mirror of a physical asset, including models of its structure and dynamics that are updated through a combination of multiple data sources. They bring significant benefits for data management and decision-making, providing a consistent, accurate single source of information. Risk models are rarely brought forward into operations--they typically exist separately within engineering, operations, and health and safety disciplines--and are mostly used in desk studies, based on analyzing historical data and offering only a static picture of potential risks. In reality, risk is dynamic, varying in time with operational conditions and the condition of the asset, but this is not captured by current risk models, which are seldom updated and lack real-time and prediction capabilities. "A single, unscheduled downtime event can cost from $2 million to $5 million per day," said Liv A. Hovem, chief executive officer for DNV GL Oil and Gas.
Sharma, Abhishek (Agora Schlumberger) | Samuel, Prince (Agora Schlumberger) | Gupta, Debashis (Agora Schlumberger) | Whatley, Craig (Agora Schlumberger) | Agarwal, Shubham (Agora Schlumberger) | Gey, Gian-Marcio (Agora Schlumberger)
In Production operations, asset performance depends greatly on maximizing the run life of equipment while reducing the cost of maintenance. Often, E&P operators have a reactive approach to field maintenance resulting in uneccessary downtime in logistics, inventory management, diagnosing the issues, and in taking the recommended actions. This can lead to higher operating costs and non-productive time.
E&P operators are aggressively looking to increase production with operational efficiency gains. In the unconventional fields, a large number of wells have been drilled and put in production with various artificial lift techniques. Proactive well and field production management requires digital enablement of operations, with no data silos and data flowing seamlessly from the subsurface to the hands of the operator. With huge amounts of data being collected, it is imperative to apply data-driven techniques to gain more insights that can be utilized to better manage production. A data-driven approach can provide huge benefits for organisations holding vast amount of reservoir, production, and facilities data. It could provide insights into non-linear multidimensional relationships between parameters so that the field development is better understood and optimized. It could allow companies using a proactive approach towards field operations and equipment maintenance resulting in additional cost savings.
This paper presents case studies in which operators optimized production utilizing edge-driven Industrial Internet of Things (IIoT) solutions. These edge IIoT solutions enable fast-loop control through a combination of physics and data-driven workflows, which empowers the operator to proactively manage their assets and focus attention on potentially problematic wells. The solution’s architectural setup and ability to deliver fast-loop control workflows at the edge enables operators to successfully detect and manage potential issues and ultimately improve well performance. Additionally, this approach reduces the dependency upon domain experts to frequently analyze data. The high-frequency data capturing resulted in predicting equipment performance with confidence and allowing remote well management to reduce health, safety, and environment (HSE) risks while decreasing logistics and maintenance costs.