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Collaborating Authors
well control
Cementing Bullheading Simulator for Well Plugging and Abandonment with Coupled Well-Reservoir Modeling
da Silva, I. E. (PETROBRAS, Rio de Janeiro, RJ, Brazil) | Rylo, E. (SIMWORX Research and Development, Campinas, SP, Brazil) | Forti, T. L. (SIMWORX Research and Development, Campinas, SP, Brazil) | Longhin, G. C. (SIMWORX Research and Development, Campinas, SP, Brazil) | Moreira, R. P. (PETROBRAS, Rio de Janeiro, RJ, Brazil) | Piedade, T. S. (PETROBRAS, Rio de Janeiro, RJ, Brazil) | Rocha, J. S. (PETROBRAS, Rio de Janeiro, RJ, Brazil) | Oliveira, A. G. (PETROBRAS, Rio de Janeiro, RJ, Brazil) | Lucchesi, R. D. (PETROBRAS, Rio de Janeiro, RJ, Brazil) | Carvalho, C. P. (PETROBRAS, Rio de Janeiro, RJ, Brazil) | Cid, K. F. (SIMWORX Research and Development, Campinas, SP, Brazil) | Santos, F. G. (SIMWORX Research and Development, Campinas, SP, Brazil)
Abstract Oil & Gas E&P operations are known for its financial and operational risks. In regard to environmental regulations, an O&G well must comply not only with the restrictions for its operational life, but also to those conceived for its decommissioned life. One such restriction involves guaranteeing that different Oil and Gas zones are kept isolated from each other after the well is decommissioned, i.e., abandoned. One of the various techniques deployed in these cases is Cement Bullheading, consisting of pumping cement down the well, so that cement plugs the porous media making it impermeable, and therefore, isolated. A cement bullheading well abandonment simulator equipped with a coupled well and reservoir model was developed to assist in the decision-making of well decommissioning processes. The numerical model covers the whole cement path, starting at the Oilrig tank, down to the reservoir, modeled through hoses, risers, tubulars, completions and rock formation. Different models of fluids are considered, such as biphasic fluids, cement paste and cement/foamed fluid. Changes in Well Injectivity are computed based on the pressure reservoir response (3D FEM Simulator) along with cake formation, which depends on the adopted filter cake model. Thermodynamic effects are also addressed during the operation, considering heat exchange between well components and reservoir, including fluids, casings, and rock formation. The main simulator output are time dependent curves, along the whole cement path, for pressure (casing and rock stress operational limits), temperature, fluid position, flowrate and when using foam fluids, the nitrogen injection rate. Results are checked against field data and so far are very promising.
- South America > Brazil (0.94)
- North America > United States > Louisiana (0.28)
Technical Challenges and Technology Advances in Well Engineering Regarding Mero Field Development
Gozzi, Danilo Signorini (PETROBRAS – Petroleo Brasileiro S.A., Rio de Janeiro, RJ, Brazil) | de Lacerda, Marina Pires (PETROBRAS – Petroleo Brasileiro S.A., Rio de Janeiro, RJ, Brazil) | de Carvalho, Renan Luiz Costa (PETROBRAS – Petroleo Brasileiro S.A., Rio de Janeiro, RJ, Brazil) | Vaz, Frederico Ferreira Chaves (PETROBRAS – Petroleo Brasileiro S.A., Rio de Janeiro, RJ, Brazil) | Abdu, João Paulo Sanseverino (PETROBRAS – Petroleo Brasileiro S.A., Rio de Janeiro, RJ, Brazil) | Schnitzler, Eduardo (PETROBRAS – Petroleo Brasileiro S.A., Rio de Janeiro, RJ, Brazil) | Teodoro, Jonathas Franco (PETROBRAS – Petroleo Brasileiro S.A., Rio de Janeiro, RJ, Brazil) | da Cunha, Rafael Curtinhas (PETROBRAS – Petroleo Brasileiro S.A., Rio de Janeiro, RJ, Brazil)
Abstract This paper outlines the main challenges and achievements in well engineering experienced during the development of the Mero oil field, located in the Libra block of the Santos Basin Pre-Salt offshore area in Brazil. With an ambitious project including more than 60 development wells, the Mero campaign is underway with several wells already drilled and completed in an ultra-deepwater environment. The plan includes wells up to 6,000 m deep, crossing formations with considerable geological complexity and heterogeneity, and a reservoir with high silica content, making drilling particularly difficult. Moreover, the use of intelligent well completion (IWC) is a mandatory feature in the project, entailing a more elaborate completion scope. Injector and producer wells have different requirements in terms of zone selectivity—i.e., 2 and 3 zones respectively—, which unfold into different completion configurations for each. The challenges encountered prompted the project team to work on continuous improvement and develop new engineering techniques and equipment. This made Mero a pioneer in the deployment of groundbreaking solutions. The implementation of open hole IWC configurations was key to improve operational performance as it allowed downsizing bit and casing diameters, besides simplifying the scope by eliminating one casing run and cementing. In the case of 4-phase wells, the conversion to open hole configuration allowed the construction of slender wells which dramatically improved performance especially in THD, resulting in a 38% reduction in mean drilling time when compared to the cased hole equivalent. For 5-phase wells, the scope simplification also proved beneficial, yielding a reduction of 21% in mean drilling time. Initially, open hole IWC was restricted to 2-zone selectivity, namely the "PACI 2z" configuration, so it was only applicable to Mero injector wells. For this reason, Mero producer wells had been originally designed with cased hole configuration. However, later the "PACI 3z" configuration was developed, which is an open hole IWC suitable for 3-zone selectivity, becoming feasible for Mero producer wells. Mero was pioneer in deploying PACI 3z and the installation was considered successful. Besides the numerous benefits, the PACI 3z configuration also presents potential risks, which must be studied and managed. Another significant innovation during the Mero campaign was the inaugural use of a Downhole Disconnection System (DDS) device, which was successfully installed in a single trip. The DDS is advantageous because it enables one-trip IWC to be run in severe fluid loss scenarios and allows reestablishment of IWC functionalities after an eventual heavy workover intervention. Finally, by analyzing the yearly evolution of mean operation duration in Mero, for both drilling and completion, a consistent improvement in performance can be observed, reflecting the project learning curve.
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline (0.68)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.55)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Mero Well (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Libra Block > Mero Field (0.99)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
- (2 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- (9 more...)
A Novel Approach to the Use of Digital Twins for Drilling Rigs Allows Better Operator Performance, While Achieving Best-in-Class Safety Standards Through Drilling the Well Virtually First
Gallerati, Piergiorgio (4DLabs Srl) | Bori, Leonardo (Drillmec SpA) | Curina, Francesco (Drillmec SpA) | Qushchi, Ali Talat (Drillmec SpA)
Abstract The definition of Digital Twin is generally associated with process control, in environments such as power plants, manufacturing plants, refineries, and other industrial places where there is the need for monitoring remotely in real time the status of equipment and instrumentation. The biggest downside of such digital twins is that they can be extremely expensive and difficult to keep up-to-date due to the complexity of their real counterpart. However, a digital twin of a drilling rig can be easily kept under control by overriding the cost issues. This gives the opportunity to drastically enhance the rig safety and reliability, allowing better planning and design, improved training methodologies, costs reduction and best-in-class safety standards. In this paper we present a novel approach to digital replicas for the Oil & Gas industry: a physical-digital replica of a drilling rig. Although the idea is not at all new - simulators have been in use in the aerospace industry since many decades, it is quite new in the oil and gas industry, especially from the competence, training, and human factors perspective. The Oil & Gas industry is rapidly evolving toward extreme digitalization, drilling rigs are getting more complex and computerized. However, even highly automated rigs need to be manned, therefore, it is extremely important that operators perfectly know the actual equipment they will be using, in order to ensure safe and cost-efficient operations. The study found that the use of digital twins for the training of drilling operators raises competence and confidence with the equipment, allowing them to familiarize with the rig and gain information on its main elements, to perceive the underlying mechanics involved and allow the realization of several attempts, if necessary, to perform tasks without the cost associated with errors in a real situation.
Well Control for Formation Test Tool – A Case Study of Kick Circulation After a Formation Test Operation
Motta, M. (SLB, Rio de Janeiro, RJ, Brazil) | Machado, P. (SLB, Rio de Janeiro, RJ, Brazil) | Reigoto, D. (SLB, Rio de Janeiro, RJ, Brazil) | Lustosa, R. (SLB, Rio de Janeiro, RJ, Brazil) | Almeida, D. (SLB, Rio de Janeiro, RJ, Brazil)
Once a formation test operation is performed, it is possible that after getting the samples from the formation an extra quantity of fluid could invade the bottomhole and cause a well control incident. The main purpose of this paper is to present a successful simulation case of how a small amount of hydrocarbon, when collected after a formation test operation, is managed under a specific scenario. The outcome is achieved by understanding wellbore conditions using an advanced well control simulator, thus abnormalities normally failing in conventional practices can be detected and explained. This improves not only safety and performance, but also allows for an effective application of resources (Davis, Selent, & Duplessis, 2019).
- Asia (0.68)
- South America > Brazil (0.47)
Real-Time Monitoring and Diagnostics Applied to False Kick Detection
Oliveira, L. A. (ESSS, Rio de Janeiro, RJ, Brazil) | da Silva, F. R. G. (ESSS, Rio de Janeiro, RJ, Brazil) | Fonseca, T. U. (Petrobras, Rio de Janeiro, RJ, Brazil) | Donatti, C. N. (ESSS, Rio de Janeiro, RJ, Brazil) | Carriço, V. H. R. (ESSS, Rio de Janeiro, RJ, Brazil) | Fasolin, K. (ESSS, Rio de Janeiro, RJ, Brazil) | Martins, A. L. (Petrobras, Rio de Janeiro, RJ, Brazil)
Abstract Kicks are one of the main safety concerns in drilling operations, especially offshore, since they could lead to a blowout if not detected as soon it starts. Sometimes kick indicators can be smoothed and it might be difficult to determine if there is a real kick or another physical event taking place within the well. The fluid temperature effect might be misinterpreted as a kick migration, generates a false alarm, and stop operations until there is enough evidence that it is not a kick, due to the severe consequences that it can lead in a real occurrence. These thermal effects can be considered inherent to the operation, given that it is natural to deep wells reach higher temperatures in the subsurface and thus the fluid could experiment an expansion associated with an increase in pressure. The proposed calculation presented in this work acts in a way to reduce the time used to evaluate these specific situations in real-time and allows a safety operation resume. After development tests, the new false-kick module was included in a drilling digital twin software, currently in use by a drilling engineers’ team, on a 24×7 service inside the client Real-Time Operation Center (RTOC). While performing tests at the homologation server/database, the results were in agreement with the expectations, proving that around 40 minutes of rig time could be saved for each false kick detection. These results add value to the operations as it provides more sensitive information to be taken into account while evaluating a kick scenario and shortens the time frame reaction to deal with an inconclusive pressure/flow check. The novelty is the usage of a drilling digital twin to include a false kick analysis, enabling it to detect whether just a thermal effect occurred instead of a real kick. The numerical simulation already runs robust data monitoring, evaluating a big amount of data in real-time, and the new feature helps reducing operation risks to resume operations faster.
- Europe (0.46)
- South America > Brazil > Rio de Janeiro (0.15)
Improved Well Integrity Using a Novel Fluid Technology to Overcome Large Fracture Networks and Permeable Formations
Shine, J. M. (Saudi Aramco, Dhahran, Saudi Arabia) | Sowailem, A. (Saudi Aramco, Dhahran, Saudi Arabia) | Gbemiga, I. (Baker Hughes, Al-Khobar, Saudi Arabia) | Bermudez, F. (Impact Fluids, Houston, Texas, USA)
Abstract It is common to hear of lost circulation and well integrity together when discussing well construction risks. Normally, it is difficult to achieve well integrity unless curing losses prior to or during cement placement allowing achievement of the isolation requirements. Losses, especially in carbonate formations, can result from fracture networks or naturally permeable formations which can be challenging to consolidate and restore the wellbore circulation. The deployment of a novel fluid technology shows success across challenging lost circulation zones where similar technologies show unfavorable results. The paper discusses the technology evolution, performance, and results from field evaluation.
- North America > United States (0.69)
- Asia > Middle East > Saudi Arabia > Eastern Province (0.46)
Modeling and Optimization of Mud Cap Drilling for Undrillable Wells Due to Loss of Circulation
Saihood, T. (Petroleum Engineering, New Mexico Tech., Socorro, NM, USA / Houston University) | Al-Safran, E. (Petroleum Engineering, Kuwait University, Kuwait City, Kuwait) | Nguyen, T. (Petroleum Engineering, New Mexico Tech., Socorro, NM, USA)
Abstract Mud Cap Drilling (MCD) is a technique from Managed Pressure Drilling (MPD), which is used when all conventional attempts fail to solve the loss of circulation. MCD places a very high drilling fluid density, called Mud Cap (MC), in the annulus above the lost zone to prevent the mud from returning to the surface. A sacrificial fluid instead of drilling mud is used to clean the hole and transport the cuttings into the loss formation. This study presents a detailed step-by-step model and design for a well in the Middle East. New equations were developed to calculate the MC height, MC density, and the position of the interface between the MC and the sacrificial fluid. The present model also depicts pump rate optimization and hole cleaning to reach an efficient drilling program. The case study presented within this paper encountered a complete lost zone and was considered as an un-drillable well. The pore and fracture pressures were calculated using drilling data from the offset well. A sensitivity analysis was performed to obtain optimal MC height and density. A complete optimal MCD design and optimal MCD operation for this well is conducted in detail. The results of this study have proved that the proposed model can be utilized as a tool to design and optimize an MCD program.
Successful Deepwater MPD Application in Drilling and Cementing Through Depleted Formation with Wellbore Instability and Loss Circulation Challenge Offshore of Sabah
Benny, B. (Managed Pressure Drilling, Weatherford Asia Pacific, Kuala Lumpur, Malaysia) | Tan, J. (Managed Pressure Drilling, Weatherford Asia Pacific, Kuala Lumpur, Malaysia) | See, J. (Managed Pressure Drilling, Weatherford Asia Pacific, Kuala Lumpur, Malaysia) | Foo, J. (Managed Pressure Drilling, Weatherford Asia Pacific, Kuala Lumpur, Malaysia) | Othman, F. (Sarawak Shell Berhad, Sarawak, Malaysia) | Mathew, M. (Sarawak Shell Berhad, Sarawak, Malaysia)
Abstract Managed Pressure Drilling (MPD) has become the essential drilling technique to drill problematic zones in these past decades due to its ability to precisely manipulate downhole equivalent mud weight (EMW). This ability empowers the operator to save time and cost when drilling through loss zone with lower drilling fluid and at the same time, able to retain EMW above the wellbore instability or, if required, pore pressure gradient. This paper describes the crucial role of MPD in a drilling operation on a horizontal deep water oil producer well in Sabah region, offshore of East Malaysia, to help the Operator recover from Wellbore Instability and Loss Circulation issues and successfully drill and cement the problematic section. The main challenge of the well is the tight drilling window between depleted sand formation and the interlayered shale formation. Therefore, the MPD Integrated Riser Joint (IRJ) was deployed along with the riser string prior drilling 12.25 in hole section. Initially, the section was drilled conventionally with wellbore strengthening techniques, only to encounter unmanageable static losses. After multiple unsuccessful attempts to cure losses, the section was cement plugged to sidetrack the well. Considering the substantial challenges encountered, the well was sidetracked with lighter drilling fluid and applied surface back pressure (SBP) to maintain its bottom hole pressure above the wellbore instability gradient and below the fracture gradient. After the well had reached target depth, the drilling assembly was pulled out of hole in MPD mode without having to displace the well to heavier tripping mud and, once it was above the Subsea Blowout Preventor (SSBOP), the well was then isolated with blind shear rams (BSR). To continue maintaining SBP below the BSR, the MPD system was lined up on a surface loop circulation in such a way that the SBP was applied to the well via kill line. With the casing string delivered to the bottom, Managed Pressure Cementing (MPC) was utilized to cement the casing by having a schedule of SBP against pumped strokes that was formulated by software simulation to give a minimum pressure surge when the cement slurry entered the open hole. In addition, the paper also describes the equipment setup required onboard a drillship for drilling with MPD in a deep-water setting. The MPD setup enables the application of advanced flow detection system and riser gas handling which are critical in drilling deep water wells. With all these features, MPD Deepwater application has successfully delivered the well to target depth which once was undrillable.
- Asia > Malaysia (0.34)
- North America > United States (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Geology > Geological Subdiscipline > Geomechanics (0.54)
Analysis of the Sources of Uncertainty in Geopressure Estimation While Drilling
Cayeux, E. (NORCE Norwegian Research Center, Stavanger, Norway) | Daireaux, B. (NORCE Norwegian Research Center, Stavanger, Norway) | Macpherson, J. (Baker Hughes, Houston, USA) | Bolt, H. (Depth Solutions, London, UK) | Harbidge, P. (Expro, Kuala Lumpur, Malaysia) | Annaiyappa, P. (Nabors, Houston, USA) | Carney, J. (NOV, Stavanger, Norway) | Ziadat, W. (Weatherford, Dhahran, Saudi Arabia) | Edwards, M. (Edwards Energy Innovation Consulting, Houston, USA)
Abstract Geopressure estimation is an important aspect of well planning and execution. However, there are many sources of uncertainty that can affect the accuracy and timing of the prognosis. These uncertainties are associated with data produced by many different disciplines at various times throughout the life of the well. As subject matter experts tend to work in silos these uncertainties are often unshared, and there is no appropriate routine performance of uncertainty propagation across disciplines. This can negatively affect decision making during both the engineering and operational phases of a well. Uncertainty requirements across disciplines are often not formulated into coherent uncertainty management. It is therefore important to understand the possible sources of uncertainty to better quantify the estimation of geopressures and to make smarter decisions. This paper describes the uncertainties associated with each estimate of geopressure, their locations in the multi-discipline silos, and the current relationship between estimates. With this comes the realization of a structure or method for combining the individual uncertainties to provide a clearer idea of geopressure estimation and its inherent uncertainty. For instance, combining wellbore position uncertainty with the stratigraphic earth model uncertainty makes possible the estimation of the spatial probability distribution of particular geopressure related observations. The sources of information for geopressure prognosis are many, spread across disparate systems with various discipline ownership. Even direct and real-time observations of formation fluid influx, borehole collapse or formation fracturing can depend on the precision of downhole pressure measurements and knowledge. Extrapolate measured downhole pressures to positions far removed from the measurement point is often necessary. This requires accurate calculation of hydrostatic and hydrodynamic pressures and the wellbore and vertical depth positions to infer pressure profiles along the borehole. These profiles are a function of the accuracy of characterization of the pressure and temperature behavior of the drilling fluid properties and the well depth. Temperature estimations depend on definition of geothermal gradients and the precision of heat transfer calculations causing a varying degree of accuracy for baseline profiles to base operational decision. It is possible to measure pore pressures in situ, or to estimate them using trend analysis of formation evaluation or drilling logs. Factors influencing the precision of the results include the actual measurement depth value uncertainty, and the impact of wellbore position uncertainty on their correlation with an earth model. Leak-off tests deliver information about geopressure margins, but the interpretation of flow-back measurements creates further uncertainties that propagate across the prognosis. The propagated uncertainties from all these sources can be derived using stochastic simulations, yielding, when combined, a quantitative assessment of geopressures. In addition, Kriging methods can incorporate new geopressure estimations in a geomechanics oriented earth model. The paper provides a list of possible sources of uncertainties and a possible categorization of their origins. It describes the causal links between the sources of uncertainties and their effect on the quality of geopressure prognosis. The purpose is to facilitate the adoption of quantitative uncertainty assessment methods by the well construction community for geopressure estimations.
- Europe > Norway (0.68)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- (13 more...)
- Information Technology > Data Science (1.00)
- Information Technology > Architecture > Real Time Systems (0.66)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Information Fusion (0.46)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.46)
Successful Application of Multipurpose Thixotropic Technology for Lost Circulation, Wellbore Strengthening through Directional Tools in Well Control Events in Colombia
Toro, Carlos (Baker Hughes) | Velasquez, Eliana (Baker Hughes) | Avellaneda, John (Baker Hughes) | Olivella, Luis Carlos (Baker Hughes) | Luna, Edgar (Baker Hughes)
Abstract Controlling lost circulation in formations that simultaneously present a narrow pore and fracture gradients window is one of the most complex situations to manage while drilling. High HSE risk generated by well control operational impacts profit by the non-productive days due to drilling equipment malfunction, quantity, and type of fluid loss, as well as potential directional tools lost in the hole when pipe should be cut down due to the impossibility of bringing the drill string to the surface and assure the well. All the risks could generate a not viable project. At the present day, the greatest difficulty for controlling lost circulation through directional tools is the limited availability of technologies and limited loss circulation material (LCM) concentration range that could be pumped through the motor and the Measurement or Logging While Drilling (MWD/LWD) with the required concentrations to efficiently sealed the formation. This limitation is associated with the high risk of plugging the downhole tools, which would cause a more complicated operational situation such as the inability to manage loss and well-control situations with catastrophic HSE events. Traditional lost circulation technologies are granular in nature and require large amounts of solids with a coarse size that exceeds the allowable pumped capability of the tools, or even technologies such as cement cannot be moved through these tools. In addition, these types of traditional pills are not part of an efficient solution when severe losses occur or for combined events with gas migration; the limited concentration and type of LCM not forming a solid, hard, compact, and impermeable structure that could penetrate the formation and develops compressibility greater than 500 psi helping to control gas migration from deeper formations. The use of LCM technologies with high thixotropic rheological behavior fluids has become a good option based on a liquid phase with a very low solid size that has the property to transform from liquid to solid states depending on the operational requirements and temperature conditions. They have been able to be implemented in situations of loss of circulation control even with the use of directional tools. Another advantage is their setting and pumpable time adjusted according to specific situations, developing the desired thixotropy and reaching compressibility strength greater than 500 psi in really short time periods. The present study shows the successful application of a high thixotropy loss control system in a well located in the Middle Magdalena Valley basin in Colombia. In this region exposed formations present high pore pressure and low fracture pressure that caused simultaneously mud losses and well control events while tripping out with motor and MWD/LWD tools. Limited pump capability does not allow the implementation of traditional circulation pills generating a high probability of losing the tools in the hole or even losing the entire well. This document shows the first worldwide application of a high thixotropy pill technology through directional tools obtaining successful mud loss control, wellbore strengthening, and gas migration with positive results.
- South America > Colombia > Tolima Department (0.24)
- South America > Colombia > Santander Department (0.24)
- South America > Colombia > Cesar Department (0.24)
- (4 more...)