What do you do when the power goes out? That situation might evoke the tranquility of putting down your smartphone and looking out the window for a few moments of quiet reflection. Or it might bring the anxiety of wondering if your indoor plumbing will freeze when the power fails on a cold, dark night. But what if it brought the panic of being in the middle of a difficult childbirth operation in a remote hospital that has access only to unreliable electricity generated by intermittent sources? That is the painful reality outlined in The Moral Case for Fossil Fuels, a new book written by Alex Epstein.
Introducing his analysis on the Macondo incident in the US Gulf of Mexico (GOM), Stan Christman quoted, "Complex systems almost always fail in complex ways." The line came from the Columbia Accident Investigation Board's report of the space shuttle Columbia explosion in 2003, but it could easily describe the explosion and resultant spill that devastated the GOM in 2010. In a presentation hosted by SPE's Drilling and Completions Advisory Committee, Christman, a member of the United States Chemical Safety and Hazard Investigation Board (CSB), outlined the failures of barriers and tests, and the problems within the Deepwater Horizon's blowout preventer (BOP) system that led to the accident. The findings were the result of a 4-year investigation conducted by the CSB, which released its report in June. The federal independent agency had access to the full set of test data in real time, some of which were unavailable at the time of the publications of other reports on Macondo.
The response to the 2010 Deepwater Horizon oil spill was affected by heat. This paper evaluates the association between environmental heat exposure and self-reported heat-related symptoms in US Coast Guard Deepwater Horizon disaster responders. Using climate data and post-deployment survey responses from 3,648 responders, heat-exposure categories were assigned on the basis of of both wet-bulb-globe-temperature (WBGT) and heat-index (HI) measurements (median, mean, maximum). Prevalence ratios (PRs) and 95% confidence intervals (CIs) were calculated with adjusted Poisson regression models with robust error variance to estimate associations with reported heat-related symptoms. The association between use of personal protective equipment (PPE) and heat-related symptoms was also evaluated.
A scientist hired by federal regulators to look for ways to reduce the risk of well blowouts said it is time for the oil and gas industry to treat kicks taken while drilling the same way doctors treat heart attacks. Daniel Fraser, a lead collaborator on a research program looking for ways to reduce the risk of a loss of well control for the United States Bureau of Safety and Environmental Enforcement (BSEE), was making a case for a more statistically driven method of measuring fluid flow changes and using that data to reduce drilling risk. Just as the oil industry has long realized that small influxes of fluid can help predict problems, doctors know that prompt action taken when a patient experiences the symptoms of a heart attack leads to better outcomes. That had little effect on patient care until response time studies showed that medical providers were not living up to their standards. Those measures led to fundamental changes that shortened the time to treatment and reduced the number of deaths.
If you look for the meaning of "automation," you will find a definition such as "automatically controlled operation of an apparatus, process, or system by mechanical or electronic devices that take the place of human labor." Another definition is "the technique of making an apparatus, a process, or a system operate automatically." I prefer the second one, not only because there is no mention of any replacement of human labor, but also because it implicitly calls for human interaction. It is the "technique of making," and we are the ones making. That is the reason this section is called Drilling Management and Automation.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Al-Alwani, Mustafa A. (Missouri University of Science and Technology) | Mutar, Rusul A. (Ministry of Communications and Technology, Iraq) | Al-Bazzaz, Waleed H. (Kuwait Institute for Scientific Research)
One of the major problems facing the oil and gas industry is the problem of lost circulation. Millions of dollars are spent every year to treat this problem. Lost circulation can be occurred due to high permeability, natural fractures, induced fractures, or caves and vugs. Many major oilfields in the world are susceptible to lost circulation while drilling troublesome formations. The aim of this work is to understand the current trends and uses of lost circulation treatments worldwide. This work will be the first part which only focuses on the trends and uses. The other part (Part 2) will be focusing on probability and cost analyses.
Lost circulation treatments data were collected from more than 2000 wells around the world. Various sources were utilized to gather data such as daily drilling reports, technical reports, petroleum literature, etc. The data were clustered based on the type of loss (e.g. partial, severe, and complete), the reason for lost circulation, and the location where the treatments applied. An interactive dashboard was created to better understand the trends and uses of the lost circulation treatments worldwide. The created dashboard is adaptive for the user's preference and can be utilized easily.
The results showed that the pill of LCM treatments was the highest treatments used to treat partial loss worldwide with a good probability of success. While the high concentration acid soluble LCM treatment showed the highest use among other treatment to treat severe loss with a good probability of success. Moreover, cement plug + high viscosity (HV) mud treatment had the highest uses to treat complete loss with an acceptable probability of success. In addition, cement plug was the leading treatment used to treat partial, severe, and complete loss with a good probability of success. Nonetheless, it is not a usual practice to use cement plug to combat partial loss since there are other cheaper alternative treatments. Finally, this work will give clear insights into the current trends and uses of lost circulation treatments worldwide.
Drilling wells in potential Unconventional gas reservoirs is coupled with challenges that expose these wells to costly failures. Elevated formation pressure and pressure ramps create uncertainty in determining the mud weight to use in drilling UC wells. Also, various sources of gas influxes create confusion in analyzing well control situations and prolong handling kicks.
This paper details the approach taken on an unconventional exploratory HPHT gas well onshore Abu Dhabi to mitigate these drilling hazards.
After a thorough analysis of the drilling challenges that were encountered on a previous well drilled in the same field (Well-A), the drilling team has identified Managed Pressure Drilling (MPD) a key enabling technology that can help in mitigating the drilling hazards of (Well-A). A task force was formed with the MPD service provider to plan the MPD system deployment on Well-B. The task force came up with a detailed MPD program to address the anticipated drilling challenges in Well-B with multiple scenarios mitigation plan.
MPD goal was to identify the right mud weight to drill the reservoir section, handle gas influxes and analyze the sources of the gas at surface to minimize well shut-in time and to enhance the overall safety of the operations by providing close-loop drilling.
Drilling the reservoir section utilizing MPD has resulted in avoiding unnecessary well shut-in and raising the mud weight. Gas influxes were handled utilizing a dedicated MPD Mud Gas Separator (MGS) instead of the rig’s one, this approach enabled smoother drilling and coring operations. The pilot hole reached the planned Total Depth (TD) across high pressure ramps, coring program was implemented without interruption and full cores were recovered as planned. Non-Productive-Time (NPT) was reduced by 60% comparing to Well-A and no well control events occurred, saving cost and building confidence in the system. Therefore, a decision was made to continue utilizing the MicroFlux MPD system in the horizontal section of Well-B.
The MPD implementation on Well-B proved that the reservoir pressure was less than anticipated by 3 ppg, thus the 15K psi BOP was not required as thought previously, resulting in reducing the drilling cost of the consecutive wells. The impact of using a lower mud weight is believed to have a positive impact on the reservoir productivity.
This paper show-cases the utilization of the Full-Automated MPD on well-B as the first application of this technology in ADNOC onshore fields. It sets a stepping-stone for future implementations and capture important lessons learned and best practices that will certainly facilitate the development of Unconventional resources fields in the United Arab Emirates. Even more, the knowledge management process applied on Well-B can support tackling similar drilling challenges in mature fields.
Liao, Youqiang (China University of Petroleum, East China) | Wang, Zhiyuan (China University of Petroleum, East China) | Pan, Deng (CNPC Xibu Drilling Engineering Company Limited) | Sun, Baojiang (China University of Petroleum, East China) | Duan, Wenguang (China University of Petroleum, East China)
In this research, a new gas kick simulator which incorporates the fully coupled heat and mass transfer model to describe the gas kick developing process, has been developed considering the unsteady gas–liquid–solid multiphase flow. Then, a series of numerical simulations are described to make a detail understanding of the gas kick developing process focusing on the variation of gas void fraction, pit gain and bottom hole pressure at various construction parameters. The numerical simulation results show that: fluid flow in annulus will change to gas–liquid–solid flow due to hydrate dynamic decomposition. What's worse, if there is no wellhead pressure control device, i.e. the wellhead pressure is equal to 0 MPa, the gas volume fraction and pit gain can reach 0.68 and 3.12 m3 at the wellhead, respectively. While, if the wellhead pressure increases to 0.5 MPa, gas fraction and pit gain only reach to 0.28 and 1.54 m3, respectively. Therefore, managed pressure drilling technology should be applied to hydrate reservoir drilling. On the other hand, if the mud inlet temperature is lower than 17.5 °C, which means a lower rate of hydrate decomposition, the gas volume fraction at wellhead can be safe and controllable. Compared with wellhead backpressure and inlet temperature, drilling fluid density has few effects on the gas void fraction in annulus. To sum up, in order to ensure safety and efficiency in hydrate layers drilling, a lower inlet temperature of drilling fluid and a higher wellhead pressure, such as 17.5 °C and 2 MPa, which mean a lower hydrate decomposition rate, can achieve the gas volume fraction at wellhead less than 10%. This paper provides some meaningful guidance in hydrate formation drilling process.
Offset wells in this region for the past 20 years were used as water disposal wells, having 40,000 bpd water production. Past decade observed remarkable decline in production leading to the development of the current well as a replacement while abandoning the previous well. The well was ranked as medium critical considered from its long water disposal period as no integrity test were performed due to the well location. The lithology of anhydrite alternation with limestone, dolomite and thin shale layers caused a risk of losses and differential sticking. In addition, this was a H2S bearing (100 - 119ppm) salt-water flow formation.
With a rotating control head in place with the flow line valve closed providing a closed loop system, the return is dumped to the sea through the extended diverter lines, ensuring that the H2S emissions are diverted away from the rig floor and from the manned complexes.
Total losses and sour water flow made closed loop flow drilling an engineering solution for its ability to ensure no H2S migration to the rig floor and continuity of the drilling operation with returns diverted away from the rig at all times. The introduction of side entry flow line on the rotating control device (RCD) allowed utilization of an additional fill up line planned to bullhead back to the formation preventing excessive gas migration.
Extensive planning of rig interface with rotating control head with side inlet connection from the standpipe manifold to manage time and space constraints in addition to losses management providing well continuity.
The well drilled successfully with a rotating control device- RCD at surface and returns diverted safely. The closed system with rotating control device - RCD and a well head pressure monitoring gauge provided an additional security of analyzing well conditions, though risk of having gas influx was initially identified as a medium hazard being a top hole section with a higher chances of losses while drilling.
As circulation and conditioning was done traces of gas and H2S were observed with an increase in pressure observed at the RCD. Bullheading from the side inlet of the RCD from standpipe was utilized to balance the well eliminating the risk of high exposure of H2S gas at surface. Having the only pressure monitoring system in place with the RCD the overhead pressure could be identified to raise the mud weight and to balance the well. This operation was successful and resulted in zero gas at surface with casing and cementing operations on the well conducted safely without any quality, health or safety issues.
Understanding the risk of less information about the formation led to the approach of utilizing a low pressure rotating head system to drill safely into a H2S risk zone. This paper identifies how a previously used system, could have an innovated approach to drill safely in a total loss and H2S prone formations.
Assaad, Wissam (Shell Global Solutions International B.V.) | Di Crescenzo, Daniele (Shell Exploration & Production Company) | Murphy, Darren (Shell Exploration & Production Company) | Boyd, John (Shell Exploration & Production Company)
In this paper, we present a method of modeling surge pressures and wave propagation that can occur during well execution. The surge pressures have an effect on formations [i.e., formation fracture resulting in mud losses and nonproductive time (NPT)]. Knowing the amplitude of surge pressure in advance can lead to operation redesign to avoid losses. Swab- and surge-pressure waves can occur at numerous events during well execution. For example, during liner operations, pressure waves can occur at dart landing or plug shearing, liner-hanger setting, or clearing a plugged shoe-track component. It is possible for surge-pressure waves to create fractures in shale and sand layers (i.e., when surge-pressure-wave amplitude exceeds formation fracturing resistance).
A transient-state physical model is built to compute pressure-wave propagation through drillstring, casing, and open hole to predict the amplitude of a surge-pressure wave and to warn when a fracture might occur in the formation, to avoid mud losses and NPT.
In the model, continuity and energy partial-differential equations (PDEs) are built for a cylindrical fluid element contained in an elastic hollow cylinder. The method of characteristics is applied to convert the PDEs to ordinary-differential equations (ODEs). The ODEs are solved numerically to compute pressure distribution along well depth and in time. The model is implemented as a graphical-user-interface (GUI) tool to be used by drilling engineers at the design phase of a well to avoid losses. The GUI tool is targeted to address different scenarios that take place during the cementation process. To date, the transient-state physical model has been applied successfully in various applications, such as monodiameter technology, running casing, and perforating operations. Two cases are studied, one for a well in the Gulf of Mexico (GOM) where mud losses have been reported, and the other for a well in Malaysia where no mud losses have occurred. Pressure-wave computations are performed with the GUI tool for the two cases. The results of both cases are presented in this paper and show that formation fracture can be predicted by the GUI tool and subsequent losses can be avoided.