The main objective of this project is to develop a model that, based on the data of previously drilled wells, allows the user to evaluate the mud plan and identify the probability of a stuck pipe event occurrence. This is done, by using statistical predictive models, particularly in this case, neural network models. The proposed model takes the input data from the Volve’s dataset. The process starts with the pre-processing of more than 24.000 rows of data from the daily drilling operation reports of 30 wells. The pre-processing of the data consists of identifying the cases where the operation ran across a section successfully or when it resulted in a stuck pipe event. Depending on whether there is or not a stuck pipe event, each row will be classified indicating the chance that a stuck pipe event occurs based on the geological and the operational conditions. In order to ease the processing of the 24.000 rows, the project workflow implements a Natural Language Processing model, which, based on an initial dataset of 1.200 rows, reads the remaining 22.800 identifying whether the row content is relevant or not for stuck pipe identification. Once all the rows are processed, the rows which represent a stuck pipe event, and those who identify a clean operation run are selected and integrated into the final dataset. Once the data is processed, the resulting dataset consists of around 600 rows. After some data transformation, this dataset will be the input for the neural network model in the training and validation phases. Once the model is built, the model is tested with the validation dataset in order to evaluate its accuracy. The trained model shows high accuracy, higher than 84% on the test data. After the model is trained and validated, it’s implemented into a frontend which will serve as the front user interface where he can upload the mud plan parameters, and obtain a stuck pipe event chance evaluation. Having these results, the user can improve the mud plan in order to reduce the chance that an event of this type occurs. The main advantage of this methodology is that it allows to include historical data from the other drilled wells, this way, boosting the mud plan design with real data and reducing the chances that a stuck pipe event, that account for a high percentage of NPT’s during drilling operations occur. Also, by the use of these statistical models, applied to a specific field, it will allow to intrinsically take into account variables such as geomechanics properties in the model.

Global energy demand has driven petroleum industry to develop hydrocarbon resources from extremely harsh formations. Ultra-high density drilling fluids are critical to successful drilling and completion practices in all of these wells. In this paper, potential weighting materials were systematically evaluated and screened to accomplish an ultra-high density oil-based drilling fluid system (19.62 to 22.12lb/gal) aimed to utilize in ultra HPHT conditions (>30000psi and >410°F). Potential high-density weighting materials were evaluated. Properties (pure density, particle size/distribution, surface area etc.) were evaluated and compared. Special treatment was conducted to optimize properties of weighting materials. HPHT filtration tests under static and dynamic conditions were conducted at higher than 410°F and 300 psi. Real cores with an average porosity of 19% and an average permeability of 50 md were used in the filtration tests. Rheological properties, sag tendency, the volume of filtrate, and the filtrate cake characterization was measured before and after heating at 410°F for 16 hours. Results revealed that ultra-micro manganese and ilmenite complex after suitable surface treatment could act as an ideal weighting material than ultra-pure barite or other materials, which could fail in rheology and sag measurement with such high temperature and density. Viscosity and filtration analysis confirmed the stability and reliability of this novel ultra-high density oil-based drilling fluid. This study developed a challenged drilling fluid system under critical conditions, as well as established a systematical laboratory evaluation and screening procedure of weighting materials and contributed recommendations on how to utilize it in the fields.

The design of an invert emulsion fluid that can hold up more than 24,000 psi and 435°F is a complicated and exhausting process. The challenges presented in the design of an UHPHT drilling fluid formulation are the base oil selection and the complete drilling fluid formulation. Flash point measurement of base oil before and after heat ageing to ensure that the base fluid were stable and the overall stability of the mud system need to be assured (rheology, gelation, fluid loss and weight material suspension) after both dynamic and static ageing for at least 96 hours at anticipated maximum BHST. Laboratory pilot testing allows us to find a chemical balance where the rheology profile and mud properties fulfill the UHPHT project requirements. The laboratory testing protocol validation is the most important factor to prevent different issues during the drilling phase. This testing will be a contributor factor to conclude a well successfully. Another phase of the design that we need to consider is an exact dynamic temperature modelling because a more precise Bottom Hole Temperature profile helps optimize the drilling process to increase the possibility of borehole stability.

Primary cementing during well drilling operations aims, among other objectives, to provide structural stability by transferring well loads to surface formations, as well as being a safety barrier between casing and formation in order to prevent undesirable flow from permeable zones along the formation. The present work discusses whether permeable zones should be cemented along with impermeable zones, as degradation of cement quality has been observed in permeable zones due to, for example, circulation losses. According to API (2010), between 1960 and 1996, 6.5% of all primary barrier losses were related to problems with cementing. Thus, in this work we evaluate the quality of well primary cementing based on the hydraulic power developed during the cementing job, in order to discuss better cementing practices. In order to perform this analysis, data is collected from Santos basin in Brazil regarding cementing of production casings and liners in pre-salt wells, with 3 or 4 phases. Results show data collected from the drilling and cementing projects for selected wells, such as cement and cementing properties (density, volume, flow rate), casing properties (depth of casing shoes, diameter, weight), cement logging (expected vs. measured cement height, adherence quality of casing-cement and cement-formation), and drilling history (related operational problems). This data is then used to calculate the hydraulic power developed and to compare the quality of primary cementing between a 3-phase well, in which cementing is performed simultaneously in the impermeable (cap rock) and permeable (reservoir) zones, and a 4-phase well, in which the impermeable and permeable zones are cemented separately. Comparison between different wells allows us to verify our concerns regarding the quality of primary cementing in permeable zones, and to attest the quality of primary cementing as a barrier during the well life cycle. Usage of the developed hydraulic power to attest the quality of primary cementing based on field data is a novel approach as a quantitative methodology for assessing well integrity and safety, becoming a tool that aids decision-making during well design, such as in selecting the number of phases or choosing appropriate cementing procedures.

In the Talara basin, the cementing of the production section represents a challenge to achieve effective zonal isolation around the pay zone and ensure an efficient hydrocarbon production. For this purpose, well cement design must be tailored to accomplish specific goals. Challenges related to depleted intercalation zones, gas-bearing formation, highly recycled drilling mud, and marginal economic incentives push operators to build a multidisciplinary team with cementing and drilling fluid service companies to optimize well cement design. The objective of this article is to present cementing lessons learned from a recent drilling campaign in the Peruvian northwest area. Cementing jobs in the Block IV of the Peruvian northwest area is usually complex due to poor zonal isolation according to cement bond evaluation tools (sonic logs). The lack of good cement quality is related to micro-channeling and loss of well integrity. In fact, things get more complicated due to the requirement of recycling of the drilling mud to cut costs. Highly recycled mud sticks to the formation walls, complicating its removal. Various measures have been taken to understand the issues behind poor cementing jobs. Proper cementing design and placement through continuous improvements in both drilling fluid and cement formulations resulted in successful cement placements with consistent outcomes in several wells. The formulation and designing of the pre-flushes, and the optimization of their rheological properties and wellbore exposure time, resulted in effective mud removal. For an 8.5 in hole, which was cased with a 5.5 in casing, the minimum wellbore exposure time of the pre-flush considered in the design was 2.5 minutes, each ending with a washer allowing the mud cake to disperse. Centralization was kept high with a standoff greater than 85%. The slurry design considered 14.7 ppg tail and 14.2 ppg lead slurries specifically tailored for the current conditions. Also, mechanical reciprocation of the casing string for about 10 ft-long strokes enabled more effective mud removal. Excellent results were obtained by the cement bond log based on the sonic principle. This log was taken 72 hours after the cementing job showed a 10 mV reduction in amplitude through the entire target zone, resulting in a 90% bonding index. The challenges related to the cementing complexities were finally overcome with a multidisciplinary team of engineers from both operating and service companies working together diligently. During this process, a low-cost and effective cementing job design was developed through continuous improvement. The design resulted in good repeatability and consistency in the cementing job.

Extended reach horizontal wells face significant challenges in drilling longer laterals with oil-base mud (OBM). A novel solid-state lubricant was developed to close the gap in limitations of liquid lubricants and OBM with respect to lubricity in long extended lateral sections. The novel solid lubricant reduces the surface contact area between the asperities (deformations) by rolling and provides a chemically bonded film on the contact areas to reduce the amount of shear stress between the surfaces. There is limited understanding of the complex mechanisms affecting the coefficient of friction (COF). The principles of Tribology (the science of friction, lubrication and wear) were used to develop the solid-state lubricant. The Stribeck Curve describes the regimes while using a lubricant, including boundaries mixing elasto-hydrodynamic and hydrodynamic lubrication. Liquid lubricants are limited at controlling boundary conditions where the COF is ruled by asperities in contact between the surfaces. The novel solid-state lubricant works on the asperities of both the wellbore and bit/BHA. In addition, the COF is improved in the mixed and elasto-hydrodynamic lubrication regimes. Several oil-based mud field samples were tested for lubricity using different methods including the EP Lubricity Meter and Dynamic Lubricity Evaluation Monitor (LEM). The novel solid-state lubricant was also tested using a Tribometer to produce a continuous Stribeck curve that enables evaluation of the lubricant in the entire lubricity regime. The results of the COF using EP Lubricity Meter were transformed calculating the Stribeck number to build the curve. The potential benefits of the solid lubricant were discussed using a model developed by the Stick Slip vibrations with Stribeck curves. A reduction of COF in the boundary lubrication region occurs when the asperities of the wellbore and the bit/BHA are in contact. This is explained by the adsorption and absorption of the novel solid-state lubricant onto the asperities, providing a smooth surface. The novel solid-state lubricant has a wide particle distribution (PSD) to cover different size and height of asperities. The Stribeck curves of the novel solid-state lubricant show that the lubricant can reduce COF in the boundary lubrication region where friction forces are highest, compared with a base fluid and other liquid lubricants.

Lost circulation is one of the major concerns when drilling a well because it affects downhole well integrity, leads to monetary losses and is detrimental to the reservoir. In drilling operations, it generally occurs when the drilling fluid density exceed the formation fracture pressure. Another concern during drilling is the gas-formation influx to the wellbore, which occurs when the hydrostatic pressure becomes lower than the formation pore pressure. Therefore, the knowledge of drilling fluid density is a key factor to the operational safety and efficiency. In view of it, a number of experiments were performed at isothermal conditions in a PVT (pressure/volume/ temperature) system with full sample visibility to study the influence of pressure, temperature and mixture composition on fluid thermodynamic properties. Based on experimental data, mathematical correlations for density, solubility ratio and formation volume factor (FVF) for methane and linear olefin mixtures have been developed and presented in this article. In addition, an empiric correlation was presented for pure linear olefin density and was compared with results published in literature. These analytical correlations are fundamental to well control simulations. They make possible the estimation of the pit gain (increase of drilling fluid volume on the surface after a kick has been taken) and are used in computational methodology of kick simulators as constitutive equations to improve the reliability of their predictions and consequently increasing the operational safety and efficiency. The equations for the density, solubility ratio and oil-FVF shown in this paper are in excellent agreement with the experimental data showing a maximum absolute deviation of 3.2%. However, as the experimental data ranged from 25°C (77°F) to 80°C (176°F) and pressures up to 103 MPa (14940 psi), extrapolation of the equation may lead to larger errors. The paper also presents a well control case study showing the practical application of these correlations.

With the increasing complexity of wells being drilled to optimally access as much of the reservoir as possible, an integrated drilling risk assessment strategy needs to be presented to address the increasing level of challenges and risks. Wells are being drilled deeper, through intervals that are heavily depleted into virgin, unexplored reservoirs. They are extending outward to horizontal lengths that were not even dreamed of several years ago. The assessment process described in this publication incorporates a better understanding of the complex geologic environment such as a multitude of pressure compartments, complex faulting and lithological variations that could potentially increase the risk magnitude. With these challenges, there is a step change in understanding and quantifying these hazards, risk liabilities and uncertainties that need to be addressed to make these projects commercially viable and be able to drill down to their designed targets without cost overruns due to NPT, and not less important, keeping a stable borehole capable of being evaluated and resulting in successful production rate. In order to address these challenges, more upfront in-depth planning and analysis must be performed. Often times, a review of the drilling issues are performed around symptoms of drilling events to respond to them, but not necessarily to determine why these events happened in the first place – the root cause. This shows when contingencies are built into a well plan to account for the NPT consequences of these drilling events observed in offset wells. In order to proactively address these increasing risks and hazards, development and incorporation of a detail risk mitigation strategy is required. Through experience, leveraging drilling, geomechanical and geological models in the risk assessment process, has proven to be successful in understanding the hazards that are present. Bringing out the potential hazards is just part of the strategy. A multi-discipline team needs to analyze each potential hazard and determine the best mitigation strategy to mitigate that risk down to a safe, acceptable level. The collaboration of a multi-discipline team is the key component to understand all the different drilling, geological, geomechanical and fluids influences on the potential hazard. With this type of approach in assessing the risk, the process can then address all the potentially different variables required to design an intelligent, proactive drilling strategy. Even with the best strategy in place, there are geologic uncertainties that still need to be analyzed. Knowing these uncertainties, this multi-discipline team designs a mitigation strategy utilizing the right mix of technologies and real-time monitoring component to be able to update models to fine-tune the drilling window and to provide recommendations while drilling - to optimize the drilling process. Showing that this process is effective, several results will be discussed, demonstrating the value of incorporating a pre-drill risk assessment along with real-time monitoring to reduce drilling time, uncertainties and to successfully provide safe and predictable operations from start to finish that provide ideal wellbore conditions for completion.

An automated system was developed to determine some physical properties of the drilling fluid in real time during drilling operations. Rheology, density, electrical stability, total solids suspended and water in oil ratio were determined in real time during onshore drilling operation. This work presented the results obtained using the system, comparing it with data obtained by standard offline methods according to API. The first stage of the development was performed in laboratory where the monitoring container was connected to a fluid flow loop was built. Rheology was determined using an inline modified concentric cylinder viscometer. The device was capable of determining shear stress at different shear rates. Density was determined by a Coriolis device, electrical stability was calculated by a self-designed device built under API technical design, water in oil ratio was provided by electromagnetic means of a commercial device and total solids suspended was calculated using a developed material balance equation, which uses real time data of density and water in oil ratio as inputs. The entire system was assembled into a skid, fully automated and controlled by in house developed software, adequate to be transported and installed at rig sites. The second stage was to test the system in onshore rig sites in northeast of Brazil. With automatic control of flow rate and pressure, the system performed measurements in the rig site drilling fluid, pumping the fluid in and out of the system, operating as a bypass of the main pressurized drilling fluid flow line. The system reported data locally on a screen and transmitted to a remote operations center. Density, electrical conductivity, total solids suspended and water in oil ratio were provided at every second. Viscosity profile was provided every 30 min with calculation at 6 different shear rates, in accordance to API. Electrical stability tests were performed every 30 min with 1 min of duration. The developed system performed measurements properly in the onshore rig sites. All technical requirements for operational safety were met, as well as environmental and electrical hazard managed. Overall statistical deviations calculated between online and offline reference data reported were considered satisfactory. The system constitutes the most complete project for real time fluid monitoring properties in real time. Several fluid properties (electrical stability, water oil ratios) were measured online for the first time. These properties are a requirement for real time diagnosis software and an essential input for autonomous drilling projects.

One of the critical conditions in cementing operations of gas wells, is the underbalance that generates the entry of preflush in the annular space, especially with the use of in the fluid train, therefore, trying to ensure the pore Pressure control incorporating to the fluid system, only an extensive volume of Spacer. In this way a possible gas inflow is avoided that would lead to enormous economic losses, however in terms of a good removal, just having a spacer in the preflush system would only be Fulfilling a single function that is the drag of suspended solids. in the annular space without being able to disperse and reduce its solid structures. Our methodology has been proven in fields with high GOR and good petrophysical and reservoir conditions, which intend to add a volume of washes to the preflush system, thus Hydrostatic Balance with a low Rheological Spacer volume behind the mud. The preflush system is by batch and pumped at 4.0 bpm continuous, considering a volume of 20 barrel máximum to generate a contact time greater than five minutes, thus improving the conditions of removal, diluting, dispersing and moisturizing the wellbore and casing external. It evaluates Primary cement Using bond logs that was run three days after the cementing operation. The logging results indicate an average amplitude of around 5 mV, so the 5 ½" in. Casing cement job had 90% average bond index. Good zonal isolation was achieved. In addition, Mechanical factors such as reciprocating the casing once carried to Depth, and casing centralization with Standoff greater than 80%, guarantee zonal Isolation in the área of productive. The addition of a Surfactant to the formulation of the washes favors the water wettability of the wellbore in fron of cement. The use of surfactants in preflushes entrain invading gas downhole and créate a stable foam. This foam then presents significant resistance to flow, thereby limiting upward migration ( Marrast et al, 1975 ). With regard to the properties of grouts dominate the rheologic behavior, with filtrations less than 50 cc /30 min, and compressive strength greater than 1,100 psi

The present study aims to propose a methodology to treat probabilistically the prediction of well bottom pressures during drilling, circulation and tripping operations. The pressure generated by the fluid is the primary safety barrier and its failure can immediately initiate gains and losses events in the well, with a direct impact on the safety of the process. Two models were considered in the study: a two-phase flow model commonly used to predict hole cleaning and downhole pressures while drilling and a pressure propagation single flow transient model (which considers fluid compressibility and gelation) to account for peaks in tripping and pump restarts. A Monte Carlo method coupled with a latin hypercube strategy was implemented to propagate the uncertainties in the input variables to the resulting pressure. The probabilistic approach aims to consider the uncertainties in the input variables (weight, rheology, penetration rate, drillstring velocity and acceleration, pump flow, particle diameter, well trajectory, etc.). Monte Carlo Simulation was conducted to generate the pressure distribution curves in each of the operations: drilling, circulation, tripping and pump restarts. Probabilistic pressures are fit into probabilistic operational windows allowing the quantification of the risk of losing the barrier. The paper also details the critical aspects associated with typical pre-salt well drilling project conditions in offshore Brazil where narrow operational widows are a reality. The analysis directly impacts the choice of drilling strategy (conventional or MPD) and, consequently, rig selection. Innovative strategy to enable risk assessment strategies in the analysis of safety barriers. Pilot to a major integrated approach which will include other barriers such as cement, rock and equipment.

The objective of this paper is to present the improvement in zonal isolation and cement sheath properties using foam cement in heavy oil Chichimene Field in Colombia. Achieving complete zonal isolation in the pay zone have become a major challenge in these fields, recently, given the complexity of the reservoirs: high permeability, low pressure, highly fractured, depleted, low fracture gradient, and cement column for well integrity. Despite advances in drilling technologies, such as MPD, massive losses still represent a major risk both drilling and cementing. Using commonly known cementing methods, like stage tool cementing and conventional slurries, have led to fair results. Foam cement technology emerged as an appropriate cementing method given its great properties both being pumped down, and once set Foam cement has several advantages over conventional methods: it prevents losses, enhances displacement efficiency in the annulus, provides a unique feature of density/strength ratio, and has improved resilience and elastic properties once set. Production liners in Chichimene and Castilla field have been cemented successfully with foam cement, even under severe well conditions as partial to severe losses. Full returns have been observed in all jobs while cementing, and cement has been seen at surface after circulating fluids out of top of liner. Good isolation has been obtained as per cement log evaluation. Foam cement has proved to be effective cement method to achieve proper isolation in difficult wellbores and has been of great benefit for cementing production zones in the mentioned fields. Novelty of the cementing process, described herein, delivers unique engineered features that have proven a major benefit to ensure well integrity in the fields. Cementing under critical wellbore conditions, still account for many costly remedial works, and this novel approach for cementing showed its benefits to achieve excellent results. Content of this paper could benefit many operators dealing with critical wellbores.

Simulation of drilling processes involves the seamless integration of strongly coupled physics, numeric, and economic models. Operators desire advanced drilling simulation software that can mimic reality and yet be practical for daily operations. At the same time, academic researchers are devoting time and effort to develop robust and accurate models of every module of an integrated drilling environment but are challenged with translating their original contributions into the operational setting. We seek to solve both of these issues through a distinctive collaboration consortium based on an open-source paradigm. We describe and propose an advanced drilling simulation developed through a joint industry consortium at Texas A&M University. The simulator provides free access to sophisticated and reliable drilling dynamics solvers. This includes drill string dynamics, torque and drag analysis, geologic modeling, hydraulics, and wellbore pressure modeling, visualization, and operator interfaces. The simulator is written in C++ and is built on top of high-performance open source libraries that leverages parallel computing, GPU acceleration, multibody, and computational fluid dynamics solvers as well as other tools (see figure for further details). We will assist industry and academic users to employ our open-source tool. In addition, we will help said parties further develop our framework into proprietary and protected business software via the addition of custom functionality. The simulator core was successfully developed and has been used to model horizontal drilling, while providing near real-time performance. The framework has been used in several applications successfully, including modeling shallow horizontal jetting, rock drilling, and steering; as well as reconstructing spatial data from high fidelity downhole signals for borehole evaluation, and the development of improved downhole navigation algorithms. We believe that a collaborative development effort between academia and industry will bring solutions to complex modeling needs faster and more economically than any individual endeavor. To this end, the authors will also show how one can partner with Texas A&M University to obtain access to the open-source enabled drilling simulation framework and platform to collaborate, improve and create solutions for new and existing problems.

In Mexico, the development fields of the northeastern marine region have complex geological structures, which have formations with thicknesses that limit well directional operations, especially those related to the construction of high-angle curves in the reservoir. Derived from the current challenges and demands in well drilling, the requirement of a greater area of ​​contact in the reservoir to increase the oil production, causing the drilling of wells in a high angle and forcing the use of various technologies to minimize drilling risks, turning them into methods for optimization. This technical document shows the application of resistivity technology close to the bit, providing added value to geological control and monitoring during drilling, allowing the collection of information as a key point for critical casing points. When drilling of a horizontal well, the problem of performing high angle curves in formations with risk of generating non-productive times is addressed, as well as the reduced thickness in certain areas of the reservoir are limiting for the construction of the horizontal section. Performing the correct casing point at the top of the reservoir allows the anhydrite zone to be isolated, which represents a potential risk during drilling. As a result of real-time monitoring of the resistivity at the bit and the interpretation of structural geological information from correlation wells, minimization of the uncertainty to casing point in the desired formation was achieved, providing a wide vertical thickness margin, to achieve planned trajectory and position the well within the desired rock unit.

During the last 7 years the number of projects and operators using drilling with casing has increased steadily in both the Vaca Muerta shale play and in the Golfo San Jorge mature projects. The following paper summarizes the evolution of the use of this technology and the benefits it has brought to operations in Argentina. Additionally, as some premature failures occurred, the paper identifies some limitations of the technology and the lessons learned from those failures. Within this paper, detail will be presented for the current use of Drilling with Casing (DWC) technology in shale operations and mature fields in Argentina. A summary the drivers and benefits of the technology along with its limitations will be presented. In particular, the paper will include the analysis of some premature failures with a set of recommendations to minimize the risk of failure. Several operators are using DWC in their operations in unconventionals fields in Vaca Muerta and in mature fields in the Golfo San Jorge Basin. The highest percentage of the strings installed is for surface casing where the main target is to reduce Non-Productive Time (NPT) during drilling. The use of DWC has extended to almost all projects in Vaca Muerta, making it a standard technology for the surface casing section in one of the most important shale plays outside of North America. In the Golfo San Jorge basin, the DWC technology has been used to overcome drilling challenges of mature fields with extensive water flooding, wellbore instability, inflow control and differential sticking. The results have helped operators to reduce NPT. The technology has proven its reliability with more than 1200 strings installed in the last 7 seven years. However, some premature failures have occurred and resulted in an intensive investigation by the casing manufacturer. The failure analysis showed that fatigue was the most common mode of most of these failures. The challenge rose when the available fatigue modes could not predict or replicate the failures. Within the paper we detail the probable sources of loads that provoked the failures and some recommendations that will help to minimize the risks for the future. The use of DWC and its benefits in Argentina could be replicated elsewhere reducing costs and improving efficiency. The set of reccomendations of the paper could help to reduce the risk of future operations.

The Talara Basin in Perú is a mature oil field where production is extremely marginal, and well-construction designs are tailored to this condition to optimize well costs. However, one well recently drilled in this area was identified with the original reservoir pressure, and the well design was not based on this pressure. As a result, drilling issues such as fluid loss and lost circulation were carefully monitored while trying to control reservoir pressure in a long open-hole section. The challenges faced while cementing a high-pressure zone with controlled fluid losses and achieving well objectives in terms of safety, reliability, and lifetime zonal isolation of the well are discussed. At the planning stage, a mud density of 13 lbm/gal was considered adequate to control downhole pressure (overbalanced); however, before reaching total depth, signs of high pressure were observed while drilling through a low-permeability formation. Mud density was significantly increased to control the well while monitoring the fluid return. When the mud weight reached 15.5 lbm/gal, losses were reported. Finally, the well was stabilized at 15.8 lbm/gal using different lost circulation pills. This event complicated the cementing operation because it substantially increased the necessary slurry density (16.1-lbm/gal lead and 17-lbm/gal tail). Nevertheless, proper cementing design and effective slurry placement using conventional techniques resulted in successful cementing operation with full cement return to the surface. High-density cement slurries were successfully mixed and pumped regardless of their highly viscous property. The cementing unit and personnel were able to manage this vital operation without facing major problems. Before bumping the plug, circulating pressure was close to the theoretical value, confirming that the cement slurry column was as per the design without noticeable losses into the formation. Full cement returns confirmed a successful cement placement. Final circulating pressure was 2,370 psi, and it increased to 2,900 psi when the plug was bumped. The cement evaluation log obtained after 24 hours indicated good bonding, effective mud displacement, and a successful cement operation. The well was then fractured and put on production. Neither corrective work nor a well-integrity remediation operation was necessary. Drilling the abnormally pressurized well was extremely challenging because of unexpected high pressure and associated problems, including working with high-density slurries and using various fluid additives to achieve adequate zonal isolation for future stimulation works. Techniques involved and experiences gained while undertaking this considerably challenging project are discussed in this article.

This paper presents an experimental investigation of the time-dependent desorption of methane from non-aqueous base fluids, for a better understanding of mass transfer processes involved in riser gas events. A laboratory-scale experimental apparatus was developed and used to experimentally evaluate the rate of desorption of methane from Internal Olefin (IO) and Internal Olefin emulsions, which are commonly used as base fluids for offshore drilling in the Gulf of Mexico. The main test column of this apparatus consists of multiple sections that can be accessed separately. Methane was injected from the bottom of the test section to saturate the fluids at given starting pressures. Upon reaching complete saturation, the pressure was rapidly reduced and the methane that liberated out of solution was measured to determine the rate of degassing over time. The experimental tests were performed under various starting pressures and with different Oil/Water (O/W) ratios of Internal Olefin emulsions. Experimental results are discussed to comprehend how pressure and base fluids affect the desorption processes in the test column. This study discloses how methane evolves out of base drilling fluids commonly used in offshore drilling. The results can be used to improve well control simulators and help to better determine riser gas equilibrium through enhanced modeling of time-dependent degassing.

The Perla Gas Field is a naturally-fractured carbonate formation in offshore Venezuela that often requires advanced technology to complete and optimize drilling operations while also minimizing nonproductive time (NPT). To overcome the challenges and reduce NPT demonstrated on a well drilled in 2010 in the Perla field, continuous circulation and managed pressure drilling (MPD) technologies were used to drill two subsequent wells in 2016. Drilling in the Perla field is a challenge because of its narrow pore pressure and fracture pressure window, which increases the potential for issues such as lost circulation, kicks, wellbore instability, and connection gas. To overcome challenges encountered in 2010 while also decreasing NPT, a combination of MPD and continuous circulation technologies were selected to drill the wells. To navigate the tight drilling windows, MPD was selected for this campaign, with continuous circulation implemented to supplement the MPD process by removing any transient time or pump cycling effects during connections. Continuous circulation allows the operator to circulate fluid downhole during the drill pipe connections. The system includes a manifold connected into the standpipe that performs the diversion, and subs installed onto the top of each stand of drill pipe, creating two independent flow paths for drilling an open hole section. MPD creates a closed loop system and allows the operator to safely add or remove backpressure at the surface in order to control bottom hole pressure (BHP). In Perla, a well was drilled in 2010 with significant losses as a result of an unexpectedly narrow drilling window of 0.5 ppg equivalent mud weight between pore and fracture pressures (9.8 to 10.3 ppg, respectively). In 2016, the new combined solution enabled drilling of the lateral in both wells by maintaining a constant BHP during all phases, mitigating influxes or losses, removing static mud pressure spikes (breaking gels), reducing connection gas, and improving hole cleaning. A statically underbalanced 9 ppg fluid was used while targeting a 10.2 ppg equivalent mud weight throughout the length of the 8½ in lateral on more than 150 drill pipe connections to decrease tripping time, get liner to depth, and improve the estimated time to total depth, decreasing overall risk, NPT, and cost. In exploratory and development wells, risks increase when different than expected well conditions are encountered during drilling. This case study provides an example of the viability of combining MPD and continuous circulation, a solution which is highly applicable in offshore Latin America, including but not limited to Venezuela.

In 2019, a well operator in North Sea UK executed a conductor batch drilling and cementing campaign consisting of eight 28-in conductor casings. With the aim to further optimize the cementing operation efficiency and reduce wait-on-cement (WOC) time, thus helping the operator to reduce drilling time to complete this batch drilling campaign, the cementing service company used an integrated approach with the application of dual-component cement blend with high compressive strength development and inner string stabbed-in cementing technique in this conductor batch cementing campaign. The common cementing objective for conductor casing is to provide structural support for the wellhead by having the top of cement in the annulus at the seabed, depending on the well fatigue limit analysis result. With the weak unconsolidated formation at shallow depth and the low seabed temperature, the challenge was to provide an engineered cementing solution with high early compressive strength development rate at low temperature and of lighter density to avoid fracturing the weak formation. The cementing service company formulated a dual component cement blend to provide such a cement slurry by combining the rapid hardening cement and hollow silicate spheres. To further optimize the drilling operation efficiency from cementing perspective, an inner string stabbed-in cementing technique with double float casing shoe was used to eliminate the time to drill out cement left inside the casing shoe track. The 36-in. open hole section was drilled to 310 m, and 28-in. conductor casing was cemented with a lightweight rapid hardening cement slurry. The cement slurry density was formulated at 1.5-SG with seawater as the base fluid to further accelerate the setting time and compressive strength development of the cement. This paper discusses the risk assessment and safety factors that were considered in the cement job design phase, including the laboratory testing that was carried out according to API RP 10B-2 standard. The well operator successfully released the conductor casing weight without any significant movement after 6 hours of WOC time, 8 hours faster than the conventional conductor casing cement job with class G cement slurry. The execution of the conductor casing cement job with the inner string stabbed-in cementing technique was successful and eliminated an estimated operation time of 4 hours to drill out cement in casing shoe track. The conductor casing batch cementing job successfully met the well timing objective set by the well operator. An estimated 96 hours was saved from the conductor batching campaign with this integrated approach to optimize operational efficiency from cementing perspective. This paper will help to establish a solid case history for well operators to further improve the drilling operational efficiency for conductor drilling.

Given the complexity and high costs associated to ultra deepwater drilling, any effort to avoid unforeseen situations is beneficial. Initiatives to optimize the drilling process in real-time are extremely important. This article details the experience of 6 year operating a real-time software with the focus of anticipating the detection of potential drilling problems in challenging scenarios. Based on transient numerical simulation (hydraulics, cutting transport, torque and drag, etc.), the software automatically identifies operational problems in real-time, providing to the rig crew anticipated information, so that, corrective and/or preventive actions can be taken. The software incorporate relevant experimental and theoretical research developed in multiple Brazilian universities and R&D Centers. It receives surface and downhole data in real-time, as well as, simulates comprehensive models (which considers real data, fluid properties, well and drilling column geometry as inputs) in order to analyze the current drilling status, by comparing real and calculated (expected) data, with quantitative criteria. Dedicated decision trees, validated by a representative group of senior drillers, provide reliable indication for problem alerts. The present paper aims to detail the successes and the difficulties of detecting typical drilling problems in Campos and Santos basins (offshore Brazil). The process of algorithm development, validation and field implementation is detailed. In July 2014, after almost 10 years of development, the use of the application started as a service conducted by a drilling engineering team, on a 24x7 service in Petrobras Real Time Support Center. Since then, it monitored every Petrobras offshore well. According to estimates, the economy by using this real-time program reached almost 150 rig days, which is equivalent to approximately US$ 130 MM. In 2016, The iniciative was granted the Technological Innovation ANP (Brazilian National Petroleum Agency) Award as recognition by its relevant results. This software is in a continuous development process, aiming to acquire new analyses in order to increasingly help the Petrobras drilling operations. The novelty is the usage of numerical simulation in order to withdraw the subjectivity of a qualitative data analysis, avoiding the misinterpretation of a possible operational event. Present challenges include the proposal of hybrid solutions (modeling + machine learning) to tackle the identification of complex problems (such as false kicks, stuck pipe in salt drilling and circulation loss prediction).