Relief Well Challenges and Solutions for Subsea Big-Bore Field Developments Eric Upchurch, Chevron Energy Technology Company; Ray Oskarsen, Prasongsit Chantose, and Morten Emilsen, Add Energy; and Brett Morry, Trendsetter Engineering Summary In subsea environments, using large-bore/high-rate well designs is often a key contributor to the economic recovery of hydrocarbon resources. Their use is a necessity for accommodating the huge production capacity of the reservoirs they penetrate, with the major ben- efit of minimizing the number of wells necessary to develop a subsea field. The enthusiasm for using such well designs, however, must also be tempered by a clear understanding of the considerable well control risk they introduce—that risk being an increased level of dif- ficulty in bringing such a well under control if a blowout were to occur. It is common that multiple relief wells, with their inherent com- plexities and time investment, would be simultaneously required to bring a big-bore blowout under control. The discussion of this fact is, though, not a common topic in industry literature. Instead, capping stacks have been more the focus. Much recent attention has been trained on ensuring that capping stacks are a viable method for quickly responding to a high-rate subsea blowout. This makes sense in light of the simpler, and publicly more palatable, concept of rapidly installing a capping stack on a blown-out subsea well. Still, a cap- ping stack is only as reliable as the wellhead it must connect to. It is because subsea wellheads have such a high chance of being dam- aged during a blowout that relief wells will always be relied on as the ultimate backstop for ensuring that a subsea blowout can be brought under control. This reliance on relief wells, as they are traditionally envisioned, has limitations though when addressing a high-rate subsea blowout. Any subsea relief well will have inherent limitations resulting from the architecture of choke and kill lines (flow restrictions) and that of the crossover piping at the blowout preventer (BOP; erosion concerns). In the world of high-rate subsea blowouts, these limitations can sometimes translate into multiple relief wells being required to inject fluid at the rates necessary to affect a dynamic kill. However, the simultaneous use of multiple subsea relief wells to dynamically kill a single blowout has only been tried once in the industry’s history. As a result, some countries require that stopping a blowout must be possible by drilling only one relief well. In this paper, we describe methods that can be implemented to transcend traditional relief well limitations via using a relief well injection spool (RWIS), with the ultimate goal of dynamically killing a subsea big-bore blowout using a single relief well. The technique varies with water depth. In both shallow-water (826 ft) and deepwater (8,260 ft) environments, the techniques are presented and analyzed that will allow using a single subsea relief well to perform a dynamic kill using 15 lbm/gal drilling fluid injected at 238 bbl/min. This particularly severe scenario, based on a big-bore gas well development in Western Australia, is chosen so that our results will have applic- ability to most subsea well control events that might arise in the future. Introduction The use of subsea big-bore wells [i.e., those with a production tubing outer diameter (OD) of  7 5 / 8-in.] is becoming more commonplace in the development of oil and gas fields. Somewhat coincidental with this progression, and very much in response to the 2010 Macondo blowout, the subsea oil and gas industry has put a major focus on the development of and deployment systems for capping stacks. This is made clear by the volume of post-Macondo SPE publications that pertain to or reference capping stacks (69), where only one such publication (Adams et al. 1987) existed prior to Macondo. Today, capping stacks and the organizations to deploy them are in place and well prepared to globally respond to the next subsea blowout that might occur. That level of capping stack preparedness and our indus- try’s expertise in drilling relief wells, although necessary, should not be considered wholly sufficient for responding to a possible big- bore subsea blowout. There are multiple contributing factors as to why this is true, some of which are concerned with the uncertainties of deploying capping stacks and some with the uncertainties related to relief well drilling and dynamic kill operations. Capping stacks are truly the appropriate first line of defense in responding to a subsea blowout. Their ability to be rapidly deployed in most scenarios suggests why this is so. However, there is a reason why governments and oil and gas operators require the formulation of robust relief well plans before initiating subsea drilling operations—that reason being the uncertainty of being able to connect a cap- ping stack to a blown-out well. In the progression of events that ultimately lead to a subsea blowout, and the uncertainty as to how those events will transpire, there is nothing to suggest a high likelihood of the blown-out wellhead remaining undamaged. Yet, the pre- mise of a minimally damaged wellhead is foundational to the concept of using a capping stack. It is this key, but not fatal, weakness in the philosophy of capping stacks, combined with other concerns such as loss of subsurface containment due to backpressure from the capping stack, that drives continued reliance on relief wells as the ultimate guarantee for bringing any subsea blowout under control. Given this reliance, it is prudent to understand the inherent uncertainties of our industry’s knowledge concerning using relief wells to control a subsea blowout—especially when considering their application to big-bore wells. Discharge and Injection Rate Considerations. Planning a relief well first requires an understanding of the worst-case-discharge (WCD) rate at which a blown-out well might flow. Determining that rate usually requires using multiphase fluid flow correlations—most of which are found to be reliably accurate for simplified flow regimes dominated by either liquid (such as bubble flow) or gas (such as annular or mist flow). Between these two extremes, transitional flow regimes such as slug and churn flow can be modeled with reasonable accuracy but with more divergent outcomes between models because of flow regime uncertainty. Those uncertainties, however, are less for small pipes than large—which can have implications for big-bore wells. The experiments upon which today’s commonly used corre- lations are founded were performed in pipes with internal diameters (IDs) smaller than 6 in. Hence, their utility for smaller pipes is well Copyright V C 2020 Society of Petroleum Engineers This paper (SPE 199550) was accepted for presentation at the IADC/SPE International Drilling Conference and Exhibition, Galveston, Texas, USA, 3–5 March 2020, and revised for publication. Original manuscript received for review 26 November 2019. Revised manuscript received for review 10 February 2020. Paper peer approved 11 February 2020. 2020 SPE Drilling & Completion 1