MudLift Drilling is a term used to describe a deepwater floating drilling system where the drilling mud is pumped from the seafloor to the drilling vessel to created the effect of dual pressure gradients in the returning mud column. The dual gradient system better matches natural formation pore pressure and fracture pressure gradients, thus, minimizing the need for casing strings. When the MudLift system is used with a conventional marine riser, the riser is filled with seawater and the mud is pumped up return lines. When used with independent return lines, the MudLift system permits "Riserless" drilling. The Riserless term refers to lack of a conventional marine riser. Smaller return lines require much less tension, may be faster to deploy and contain much less mud volume. Riserless drilling significantly reduces the loads on a drilling vessel. The subsea MudLift pump provides the means for quickly adjusting annular mud column pressure to permit faster penetration rates, to control a kick and/or to evade or escape from differential pressure sticking. Introduction MudLift Drilling is a deepwater floating drilling technique that uses a subsea booster pump to lift mud returns to the drilling vessel. Mud exerts one pressure gradient from the bottom of the borehole to the seafloor and the subsea booster pump maintains another pressure gradient from the seafloor to the vessel. Figure 1 shows a concept drawing for the MudLift system. The MudLift system includes a subsea pump and diverter system in addition to the conventional subsea BOP stack. Return lines replace the conventional marine riser for "riserless" drilling. This greatly reduces riser tensioning loads and mud storage requirements for a drilling vessel. Lopes and Bourgoyne,1 Gault 2and Snyder.3 have explained how the dual gradient system better matches natural formation pore pressure and fracture pressure gradients in deep water, thus, minimizing the need for casing strings. Figure 2 shows for an example well: formation pore pressure, fracture pressure, single pressure gradient lines for several mud weights and the MudLift dual gradient-low Mud Weight (MW) and dual gradient-high Mud Weight (MW) lines. The effects of annular circulating pressures and pressure surges due to pipe movement are ignored here for simplicity of illustration. The dual gradient-high MW is the actual mud density used with the MudLift system. The MudLift booster pump reduces the pressure in the returning mud column to, in effect, create the dual gradient system. In this example, the MudLift pump maintains seawater pressure at the mudline for a dual-low MW equivalent to seawater. Figure 2 shows that a dual gradient mud column overbalances pore pressure without exceeding fracture gradient for a much longer section of hole than a single gradient mud column. Figure 3 shows formation pore pressures and fracture pressures at 5000 feet, 7500 feet and 10,000 feet of water depth. The advantages of a MudLift system becomes progressively greater as water depth increases. Several questions are frequently asked about this concept.How should the dual gradient mud system be achieved: gas lift, pumping or other means?If seawater gradient is maintained from the sea floor to the vessel will that require a mud weight in the borehole that is too high to be achievable?How much pump pressure and horsepower are required to achieve the MudLift?How much pressure must the subsea diverter system hold?
Riley Goldsmith is president of Goldsmith Engineering Inc. in Houston. He has worked as a roughneck, mud engineer, research scientist, drilling foreman and superintendent, senior staff engineer, operations manager, and manager of engineering. His experience includes onshore and offshore assignments in the U.S. and in international operations. Goldsmith holds a as degree in chemical engineering and an MS degree in general engineering from the U. of Oklahoma. He has served on the Reprint Series (1982-84) and Editorial Review (1983-84) committees, and currently serves on the Distinguished Author Series Committee. He also is first vice chairman of the Egyptian Section. Goldsmith is a registered engineer in Texas. SummaryThis article discusses the role of engineers in drilling. Specific tasks and responsibilities are discussed to show the opportunities and challenges that are developing with the changes in drilling engineering technology.
Many cost components must be considered to determine the most cost effective deepwater production system for a particular site. Too often, only the well systems CAPEX 1 is adequately included in field development alternative studies. OPEX, RAMEX and RISKEX depend largely on reservoir characteristics, specific well system designs and operating procedures. The effect of these factors nearly always outweigh differences in well system CAPEX. Optimization of total lifecycle cost of deepwater production systems must include all of these factors.The risks associated with blowouts are often an important factor in choosing one dry tree tieback well system over another. Another important factor often overlooked is the cost of well system component failures. As oil exploration and production moves into deeper and deeper water, the costs to repair well system component failures escalate dramatically. This paper presents the methodology developed by a Joint Industry Project to quantify capital, operational, blowout risk and reliability costs associated with deepwater well systems. Five well systems have been modeled to demonstrate the methodology: a dual casing dry tree system, a single casing dry tree system, a tubing riser dry tree system, a conventional tree subsea system and a horizontal tree subsea system. Case examples demonstrate the model for these five well systems.The methodology, results and main conclusions from this Joint Industry Project are presented.
The deepwater drilling industry has been rocked by the tragic Deepwater Horizon event in the Gulf of Mexico. The incident identified a number of possible failings by operator, service contractors and the regulator which combined to lead to the ultimate results which were evident in mid 2010. This paper will assess the options available to the deepwater drilling industry in assessing the risk of various riser and BOP configurations for drilling and completing deepwater wells in moderate metocean environments. The paper will address two different systems:1. A classic subsea BOP stack configuration, 2. A surface BOP stack with a subsea isolation device (SID). Both of these configurations have merits depending upon a number of factors which include rig availability and schedule, project economics, riser integrity, BOP configuration, geological issues and, most importantly, the hazard and risks associated with each concept. This paper will identify the various technical analyses and risk analysis techniques that must be undertaken to assure the operator of the system is comfortable with each system. These include riser analysis, rig mooring and station keeping analyses, system HAZIDs and HAZOPs, and more. The idea of the paper is to provide the operator and drilling contractor with a 'road map' which will allow them to navigate their way through the various issues to be addressed. This road map will start with the concept stage (rig contracting early well planning) where issues such as project economics, rig availability and risk tolerance will provide input into the overall decision making process. The paper will next address the preliminary and detailed design stages where issues surrounding metocean criteria, rig characteristics and rig configuration and geological conditions will play a part in the overall input. The paper will describe how a project team would approach the issues. Finally as the project moves to the implementation stage the paper will describe the techniques for final assurance that the concept can be managed in the implementation stage.
A methodology was developed by a Joint Industry Project (JIP), sponsored by 12 oil companies and US Minerals Management Service (MMS), to estimate the Risk Cost (the probability of blowout during field life multiplied by the cost of a blowout) for various well riser alternatives. The methodology was demonstrated by comparing dual casing riser ("3 pipe"), single casing riser ("2 pipe") and tubing riser ("1 pipe") alternatives for SPARs and TLPs in 4000 and 6000 feet of water depth. This paper illustrates how modern risk and reliability techniques can facilitate the decision making process. Traditionally, focus has been on obtaining estimates of Capital Expenses (CAPEX) and Operational Expenses (OPEX) without much effort to assess the magnitude of the Risk Cost. Recent studies have shown that the cost element associated with risk and unreliability represents in most cases a significant part of the overall cost picture. The methodology developed by this JIP can be used to select the well riser system with the lowest total cost (CAPEX, OPEX and Risk Cost) taking site specific conditions into account.For instance, a single casing riser system costs less to install than a dual casing riser system and this difference in CAPEX becomes greater as water depth increases. Risk Costs are low with single casing risers in shallow water for relatively low pressured reservoirs, but increase faster than dual casing riser Risk Costs as water depth and reservoir pressures increase. The fundamental question is whether the greater CAPEX of a dual casing riser is justified for improved safety as compared with a single casing riser. Ultimately this question can be addressed using cost benefit analysis for the particular application.As part of the methodology development individual completion components were identified and ranked according to sealing mechanisms, installation difficulty and operating conditions to estimate completion component reliabilities where statistical data were unavailable or sparse. Fault Trees were developed to calculate the lifetime system probability of an uncontrolled leak to the environment based on individual completion component reliabilities for each alternative well system and leak size. Several hundred fault tree calculations were carried out to estimate probabilities of an uncontrolled leak to the environment (limited, major and extreme) during the production mode and each step of the well intervention operations. The leak frequencies predicted by the system reliability models developed by this JIP are very close to the historical frequency of uncontrolled leaks from well systems.Risk Costs were calculated for specific alternatives where CAPEX and OPEX were known. The methodology, results and main conclusions obtained by this JIP are presented.
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