Dynamic formation mapping and design kick tolerance among critical enablers to fully realize benefits of MPD
By Oscar Gabaldon, Romar Gonzalez Luis, Patrick Brand, Sherif Saber, Anton Kozlov and William Bacon, Blade Energy Partners; and Catherine Sugden, Sugden Consulting
Inherent to the unpredictable nature of high-pressure, high-temperature (HPHT) reservoirs and exploratory wells, especially in deepwater, are increased operational costs due to nonproductive time (NPT) and operational problems.
Typically considered after the initial well design process, managed pressure drilling (MPD) techniques are well recognized as a cost-effective approach to increasing the likelihood of achieving well and cost objectives for challenging wells with narrow windows.
However, the implementation of MPD early in the project life cycle offers further potential savings that many operators have been missing. The key to these gains is in exploiting MPD’s improvements in operational efficiency, risk mitigation and safety enhancement during well design and planning.
By including MPD in the design and planning process, the operator can optimize the design sufficiently to eliminate one or more casing strings with no compromise to the likelihood of successfully reaching target depths. In many cases, the probability of success can be enhanced.
With traditional drilling techniques, reactions to unexpected pressure events are limited to adjusting mud weight, shutting in the well, or both. These are slow and costly processes that can lead to significant hole problems and NPT. With traditional drilling, having unexpected pressure events is, therefore, highly undesirable. Its impact on design is that casing seat selection be based on conservative pressure estimates, minimizing the chance of needing to adjust the well pressures rapidly. This leads to well designs that are quite static, limited to a single base case and perhaps one or two contingencies, long before the rig is even on location.
The game changer for design with MPD is two-fold: the ability to swiftly react to unexpected pressure events without incurring NPT or hole problems, and increased information about downhole pressures while drilling. With MPD and the right planning in place, casing seats can be pushed as deep as possible based on the actual pressures encountered, and must no longer be restricted to conservative estimates established from offset wells.
This work forms part of an initial phase of a comprehensive long-term project aiming to integrate MPD into two main components of well design: MPD adaptive well design, and statistical analysis based on variations of load, strength or both.
Value added by accounting for benefits and enablers facilitated by MPD in the early stages of the project life cycle is addressed, including case studies that show cost savings due to the impact of taking advantage of dynamic processes facilitated by MPD. Guiding criteria aiming to constitute a systematic and integrated approach to ensuring well integrity and optimizing a well design, while considering the operational implications and integral cost benefits, are also proposed to the industry.
Impact of MPD on a well business case
The presence of significant risk has always characterized the oil and gas industry. In evaluating candidate wells, a business case weighs risked value against risked cost. MPD can impact both sides of this equation.
In an industry dominated by conventional drilling, the most often recognized impact of MPD on the value of a candidate value is as a contingency used to reduce the uncertainty of realizing well objectives. However, the deployment of MPD on a well can also significantly enhance much of the cost and risk profile. Below is an outline of some key areas of impact, ranked based on ease of evaluation.
- Cost impact of NPT. This is typically evaluated based on NPT reported in offset wells, addressing sources that can potentially be improved with MPD techniques. Some examples of avoidable NPT with MPD are lost circulation, well control events, hole-cleaning problems and ballooning. These have been extensively documented in multiple case history publications.
- Cost of goods and services. Materials and services used to recover from events that are deemed preventable by using MPD can be estimated. Examples are the cost of lost mud, cost of cement and other materials for remedial cement jobs, cost of tubulars, cement and other materials used to run contingency strings, lost in hole, and cement squeezes used to improve shoe or weak point integrity.
- Well design optimization. Including MPD in the well design can realize savings by pushing casing seats as deep as possible and potentially eliminating casing strings. These potentially vast savings include the flat time associated with running casing strings, plus the cost of materials. The risk of failure to achieve the well objective is also reduced, including the risks associated with obtaining TD with small hole sizes.
- Safety improvements. By reducing the probability of loss of well control, and the events that are potentially associated with it, MPD can enhance safety. The ultimate consequence is related to potential harm to the environment and personnel. This is extremely difficult to quantify since it would require an assigned value to intangibles, such as life, loss of ability to work, personal injuries and environmental impact.
- Value of AFE assurance and meeting well objectives. Even though the mean estimated cost by implementing MPD could be higher than for conventional drilling techniques, probabilities of success are increased for cost assurance, safety and goal/objective assurance when utilizing MPD techniques.
As an emerging and overlooked opportunity for significant cost savings, well design optimization is emphasized in this article. Indeed, the magnitude of the potential impact on the business case makes this an exciting area to explore and a logical place to focus efforts.
Enablers for well design optimization
Although utilization of MPD facilities brings a suite of advantages to a drilling operation, two critical enablers – dynamic formation mapping and design kick tolerance – are briefly discussed here.
Measuring the available drilling window is possible with a properly designed MPD system, allowing the driller to “feel the way down.” Operational conditions can be adjusted to the actually available drilling window, minimizing the risk of undesired events, such as losses and kicks. By deliberately and systematically adjusting the bottomhole pressure up and down, and close observation of resulting pressure changes, the extent of the drilling window can be assessed. This additional information can be used both to optimize the current operation and reduce uncertainty in the estimated drilling window going forward. Not only can casing seats be pushed as deep as possible, but decision making with respect to casing seat selection and the potential for contingencies can be made with increased certainty in real time.
In general, the minimum kick tolerance method to establish the depth of a particular casing shoe aims at ensuring specified integrity of the process, so that if an unforeseen event occurs, such as a kick, the driller has means to recover from the event, with minimal risk of losing the integrity of the well. This should be no different during MPD operations.
However, when MPD is in use, an influx from the wellbore can be detected and stopped quickly by increasing applied backpressure, resulting in far smaller kick volumes than for conventional well control responses. By following an adequate process, the team can establish the right kick tolerance parameters for the MPD operations and ensure that they can be safely implemented during operations.
Adaptive well design
With varying estimations for both the low and high sides of the drilling window, each section length could potentially range from the shortest to longest, depending on the actual drilling window encountered. These extremes, caused by combinations of the lowest possible fracture gradient with the highest possible pore pressure and vise versa, are generally deemed highly unlikely.
In between the ends of the spectrum, there are virtually infinite possible outcomes for the section length, dictated by the actual pressure window measured while drilling. Furthermore, the length of the intermediate sections impacts the fracture gradient for the next section, increasing the number of potential well architecture outcomes.
In their cited work, Sugden et al (2014) propose a bottom-up methodology to identify a limited number of possible configurations, referred to as “de-branching.” In summary, the approach identifies the shallowest shoe depth that would ensure reaching TD for the deepest section. Continuing the approach section by section, critical depths are identified such that the team can predict with a good level of certainty that a section can be skipped further down the drilling process.
A computer algorithm can quickly and efficiently evaluate the downhole window prognosis curves and produce the likely configurations. In the case of stochastic prognosis, the program can even calculate the probabilities of occurrence of each configuration.
Figure 1 shows a visual example of nine possible outcomes from the cited work, distributed along a normal distribution curve, depicting a higher likelihood for outcomes 4-6, contrasted with lower likelihood configurations 1-3 and 7-9.
By reducing the number of potential well configuration outcomes, a computer program can quickly perform pipe load checks. The authors proposed a suggested approach of applying working stress design for the most likely outcomes and reliability-based design for the least likely outcomes. These recommendations will be the subject of further refinement in future work.
As one can imagine, there are limitations and concerning aspects to consider when implementing this adaptive well design approach. Issues may be related to logistics, inventory management, information management and others. The authors intend to continue exploring limitations and an adequate approach to address them in the continuation of this work.
Value assessment examples
Case Study 1
The operator planned two deepwater exploratory wells in the West Caribbean Sea after having drilled a challenging offset with significant NPT that did not reach the objective targets. The potential savings from MPD were estimated for each of the two planned wells, considering the time savings, converted to monetary value at the daily spread cost of the rig, plus the value of the lost mud.
The results of the two-well drilling campaign exceeded the expectations and assumptions made during the cost/benefit analysis. The first well was drilled with minimal NPT reported, and the operator was able to reach the target TD of the well in one size larger hole section (12 ¼ in. vs. 8 ½ in.) while eliminating a casing string.
Figure 2 shows a comparison between the plan and the final well configuration. The second MPD well was also drilled with minimal trouble time and reached its target depth as planned.
Case Study 2
The operator of a deepwater project on the northeast coast of South America evaluated the experiences of two previous wells, which failed to meet their objectives. The NPT analysis alone showed potential savings of $2-$2.7 million by implementing MPD in their upcoming well and sourcing a rig already fitted with MPD equipment.
Furthermore, the planning team realized the opportunity to eliminate the 11 ⅞-in. liner from their base case design. The potential additional savings to the cost of the well by skipping this liner are estimated at $10 million. The authors intend to compare the project outcome to the projections calculated in the cost-benefit analysis and present in future work.
Case Study 3
The operator analyzed eight previous wells drilled in the Gulf of Mexico to evaluate the time and cost-saving opportunities by implementing MPD from a floater rig already fitted with the MPD system. The wells were drilled in waters ranging between 440 and 1,430 m. Two of the wells didn’t reach the objectives.
The operator estimated net positive cost savings for six out of the eight wells analyzed on a stand-alone basis. The wells with a negative balance averaged approximately $1.4 million each net incremental cost, while the remaining six wells averaged net potential savings ranging between $1.2 million and $27.5 million, with an average of $11 million.
Further, the team evaluated the impact of drilling more than one well with the same rig, as some of these wells were drilled on a two-well campaign with the same drilling unit. In some cases, MPD was not economically feasible on a stand-alone basis, but when analyzed on a drilling campaign basis, it was economically viable, netting potential savings of approximately $31 million, $20 million and $7.8 million for the three two-well campaigns analyzed. Figure 3 summarizes the results of the cost/benefit analysis.
Additionally, the team identified an opportunity to skip a casing string in two of the wells analyzed, based on geology and the actual drilling window as measured after drilling. By employing MPD, the operator would have been able to evaluate the drilling window during operations and safely continued to drill until well TD. Savings were estimated at $10 million per well.
This work represents the initial stage of a comprehensive long-term project aimed at fully realizing the benefits of well design optimization through the implementation of MPD, with this approach gaining traction due to the realization of missed potential. The authors propose a systematic and integrated approach to ensure optimization of well design, while also considering the cost-effectiveness of implementation.
By exploiting enablers facilitated by MPD early in the design process, the proposed approach considers the actual drilling environment, allowing the well design to be optimized, while reducing uncertainty, maximizing the probability of reaching target depths, and providing AFE assurance.
Recent case studies have demonstrated both the technical and economic value added from implementing MPD as an enabler technology to reach well objectives, company strategic goals and assurance of cost-effectiveness, rather than only as a contingency tool. Considerations for creating successful business cases have been presented and clearly showcases in which benefits significantly outweigh the cost of the technology.
For future work on this approach, the intent is to merge stochastic and probabilistic analysis used in advanced well design with the opportunities presented due to the dynamic nature of MPD. Future work will evaluate the “de-branching” process, applied to a multitude of potential well configuration outcomes, which would cover any early assumptions of the PPFG forecasts. The goal is to narrow down the most feasible cases that can be optimized as the model is updated in real time as operations progress. DC
Acknowledgements: The authors would like to acknowledge colleagues at Blade Energy Partners for their hard work and passion for knowledge.
This article is based on a presentation at the 2020 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference, 21-22 April in Denver, Colo.