Enhanced Hydraulic Modeling and Event Detection Using Real-Time Fluid Properties and Fluid Position Tracking Software

Today's oil and gas drilling operations often face significant technical challenges, especially in remote locations with increasingly difficult geological settings. Stuck pipe incidents have become a major operational challenge for the exploration and production industry, with events typically resulting in substantial amounts of lost time and associated costs. Real-time monitoring has emerged as an important tool to achieve drilling optimization in avoiding downtime, particularly stuck pipe incidents. With the addition of a predictive monitoring system, this process becomes much more effective and competent. Predictive monitoring is used for advanced real-time monitoring in Wells Real Time Center (WRTC) and operational workflows to aid in the drilling execution of complex or critical well sections. The emphasis will be on reducing the complexity of real-time data analysis by utilizing trends and deviations between modelled and actual data to monitor wellbore conditions. This monitoring system and trend-based predictive capability enable drilling teams to detect borehole changes and take preventive action up to several hours in advance. By maximizing productive time, it improves operational efficiency. Predictive monitoring can provide early warning of stuck pipe symptoms, allowing the rig and operations team to take corrective and step-by-step actions. In raw drilling data, the conditions that lead to the stuck pipe can be difficult to read and detect. Various factors may indicate potential problems, but these are frequently missed until the situation has progressed to the point where the drill string becomes stuck. This system could have provided the rig crew with advance notice of changes in downhole conditions, in this case, avoiding the stuck pipe situation. We will look into predictive monitoring adoption in Field B operation as an example. Well E is a highly deviated extended reach well (ERD), with a 12,000ft long horizontal section, exceptionally challenging in terms of geomechanics perspective as well as the well design. When original Well E was drilled, a stuck pipe was encountered which caused the wellbore to be sidetracked. Predictive monitoring was implemented to assist drilling operation for the sidetracked well, and it had been completed successfully with minor hole condition issues. The predictive monitoring system is built around a trio of tightly coupled real-time dynamic models consisting of hydraulic, mechanical, and thermodynamic that simulate the wellbore state and physical processes during drilling operations. These models work together continuously to assess drilling performance, borehole conditions, and any other associated risks. It uses dynamic modelling to accurately model key drilling parameters and variables such as hook load, surface torque, cuttings transport, tank volumes, standpipe pressure, and equivalent circulating density (ECD) in real-time.

This paper outlines an innovative approach to optimize workover re-entry wells eliminating the liner and tie-back operations by addressing challenges that had placed this strategy as not suitable in the previous history of the onshore operations around the area. The main concern deemed impossible was cementing a 7″ Production Casing from the landing point to the surface safely and successfully. This strategy is essential for the development of the field and to efficiently deliver the well count on time. The project started by designing and selecting the casing materials, required auxiliary equipment and mitigating all the risks associated with the equivalent circulating density (ECD) during drilling and cementing and refining operational procedures, the projected provided a more operationally efficient well, in a shorter time, lower cost and a more integral well with not weak points as the tie-back connections and the stage tool ports. This technique eliminates the need for running and cementing both a 7″ liner and a tieback, streamlining the process while ensuring uncompromised well isolation. Hydraulic simulation, drawing from available field data, was employed to assess acceptable equivalent circulating densities (ECDs) and pressures without risking losses. These simulations guided the refinement of cement slurry designs. A specialized lightweight cement system was suggested to address ECD margin limitations and challenges linked with conventional lightweight cement. Additionally, an expandable gas-tight system was introduced to prevent zonal communication and micro annulus in between the different reservoirs. Further enhancements included the introduction of sealing/bridging spacer to ensure effective mud removal along with the optimization of pumping rates to minimize losses during displacement. Optimized pumping rates during drilling, well bore cleaning and conditioning and cementing operations were guided by simulation data to ensure that dynamic pressures remained safely below fracture pressure thresholds. Additionally, it was decided to include higher density mud to assist in reducing surface pressures during the displacement. The utilization of a specialized lightweight slurry proved effective in decreasing hydrostatic pressure of the fluid column, thereby preventing lost circulation incidents and guaranteeing a positive indication of cement return to the surface. The drilling fluids conditioning, the spacers train and the exceptional rheology of the slurry facilitated improved mud displacement and enhanced cement coverage during placement. Furthermore, a higher solid volume fraction (SVF) in the cement contributed to reduced porosity and permeability, ensuring long-term zonal isolation and casing protection, thereby minimizing maintenance requirements and extending the well's lifespan, especially in critical reservoirs. The expandable property of the set cement mitigates for any potential micro annulus development, helping to avoid sustained casing pressure (SCP) complications throughout the well's operational life, thus reducing the need for further remedial cementing operations. Moreover, a specialized spacer system efficiently aided in mud removal and demonstrated excellent bonding, as confirmed by cement evaluation logs (CEL) conducted across the 7″ casing. This comprehensive design approach effectively eliminated additional operational costs and rig time by circumventing the necessity for further remedial interventions. This paper aims to showcase the utilization of 7″ production casing in conjunction with specialized cement design as an efficient substitute for conventional liners and tiebacks. The goal is to reduce rig costs and save time during workover re-entry wells, while also minimizing the need for future costly remedial works.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IADC/SPE 178835, “Differentiate Drilling-Fluid Thermal Expansion, Wellbore Ballooning, and Real Kick During Flow Check With an Innovative Combination of Transient Simulation and Pumps-Off Annular Pressure While Drilling,” by Zhaoguang Yuan, Dan Morrell, SPE, Aldrick Gracia Mayans, SPE, and Yahya H. Adariani, Schlumberger, and Matthew Bogan, Noble Energy, prepared for the 2016 IADC/SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed. Drilling-fluid thermal expansion, wellbore ballooning, and formation kick are similar in terms of surface observations such as pit volume gain. Each of these events, however, is solved in different ways. Treating wellbore ballooning the same way as a kick likely will result in losing the current borehole after days or weeks of unsuccessful operations. In this study, pressure-while-drilling technologies are combined with software simulations to differentiate drilling-fluid thermal expansion, wellbore ballooning, and formation influx during riserless drilling operations. Wellbore Events Thermal Expansion. Because mud density is dependent on temperature and fluid compressibility, volume gains or losses because of thermal effects may be substantial, especially in high-pressure/high-temperature and deepwater wells. Thermal expansion typically results in small volume changes and low flow rates because it takes time for the mud to heat up after circulation stops. Depending on the downhole conditions, however, muds can heat up sufficiently to produce significant flowback for a short period of time. Formation-Fluid Influx. If the mud-weight hydrostatic pressure is insufficient to contain formation influxes, when the pumps are shut down, the loss of the frictional pressure created during pumping can allow formation fluid to flow into the wellbore, assuming the formation fluid has sufficient mobility. This is described as a kick, or formation-fluid influx. It is verified by performing a flow check and observing mud returns at surface over time to determine a trend in pit gain. A steady increase or accelerating trend will be interpreted as a kick, although, in many cases, the well will be shut in before a clear trend can be established. U-Tube Effect. In riserless drilling, two different fluid densities exist—in the annulus (mud and seawater) and in the drillstring (mud). Because fluids flow from a higher-pressure area to a lower-pressure area, a U-tube effect will occur once the pump stops. This will show as flow at the wellhead with a high flow rate initially, declining as the U-tube effect equalizes. The volume contribution from the U-tube effect is relatively simple to quantify, so, in the cases where surface volumes are measured, this effect will be somewhat easier to distinguish. Wellbore Ballooning. Changes in equivalent circulating density (ECD) and hydrostatic pressure can result in wellbore ballooning, where the formation takes drilling fluid when pumping and the injected fluid then flows back into the well when the pumps are shut down.

A hybrid methodology is presented to predict equivalent circulating density (ECD), which combines autoregressive integrated moving average (ARIMA) and back propagation neural network (BPNN) models. Research results are compared to previously published ECD prediction method that is based on theoretical calculation of hydraulic parameters. The hybrid methodology is based on data analysis theory. It uses ARIMA model to capture the linear trends of ECD, and then the BP neural network is used to predict the nonlinear and stochastic change law of ECD. Finally BP neural network prediction results are used to correct the prediction error of ARIMA to get the ECD prediction results. With a deepwater well in the South China Sea, a simulation experiment is carried out to verify the comprehensiveness and accuracy of the method presented in this paper. The prediction results are similar to those of the traditional hydraulics model, which considers the effect of temperature and pressure on drilling fluid density and rheological parameters. Comparisons are also provided for three classical time series prediction models, including the support vector machine, multiple linear regression and grey prediction. The root mean square error (RMSE) and the mean absolute deviation (MAD) were selected as evaluation indicators. The comparison results show that the hybrid model can reflect the variation law of ECD more accurately. Therefore, relative to the traditional methods of prediction, the hybrid methodology has the advantages of advanced modeling thought and simple operation, and it can be selected for prediction of ECD. Because of the effects of high temperature, high pressure and uncertain factors, the accurate prediction of ECD is very difficult. This paper provides a novel idea for accurately predicting ECD by analyzing the implicit relationship of ECD series data through data mining.

With drilling operations continuing to venture into increasingly complex environments, particularly in deepwater and high-pressure, high-temperature (HPHT) settings, the demand for intelligent, real-time fluid management strategies continues to grow. Traditional rheological models often fail to capture the nonlinear and transient behaviours of drilling fluids under the dynamic downhole conditions encountered in these complex environments. This paper presents a conceptual framework for integrating machine learning (ML) into drilling fluid systems to facilitate predictive modelling and adaptive control. The proposed framework architecture combines real-time sensor data, feature engineering, supervised learning models, and decision support layers to forecast key fluid properties. These include viscosity, gel strength, and equivalent circulating density (ECD). Potential use case scenarios are discussed, including early barite sag detection, fluid loss prediction in fractured zones, and dynamic ECD optimisation. Implementation challenges related to data quality, model generalisation, system latency, and interpretability are explored, along with future research directions. By bridging data-driven modelling with operational decision-making, this work lays the foundation for the development of intelligent, self-optimising fluid systems in next-generation drilling environments.

A number of oil fields in the Gulf of Thailand are characterized by severely depleted gas sands and unstable coal and shale. Operators drilling high angle and horizontal wells in those fields often have to contend with problems associated with high equivalent circulating density (ECD) and the narrow operating margin between fracture gradient and borehole stability. Reaching total depth in those fields without losing returns is possible but it requires careful management of the ECD, vigilant hole cleaning practices, and controlled drilling. Unfortunately, success comes at the expense of drill time which is unavoidably reduced by those same conventional practices. Automated Managed Pressure Drilling (MPD) was a solution used by one operator to improve drilling efficiency while still avoiding losses and maintaining wellbore stability. By taking advantage of the MPD system’s ability to manage the BHP when the mud pumps are off the operator was able to reduce the static mud weight below wellbore stability and the ECD below the fracture gradient. With the reduction in mud weight the operator was also able to change the mud rheology in other ways that contributed to improved hole cleaning. Managed Pressure Drilling was initially used in a three well program in 2007 and later in an extended six well program in 2009. For most of the wells the drilling plan was the same: conventionally drill out of the 9–5/8” casing with an 8–1/2” bit down to the top of the depleted zones, lighten the mud density and rheology, bring the MPD system on line and drill through the depleted zone to the next casing point. However, midway through the second program the well plans changed and MPD was used to drill the entire 8–1/2” section. For all nine wells, the MPD system remained the same: a dynamic pressure control system with an integrated real-time hydraulics model, an automated manifold and backpressure pump, and early kick detection equipment. Even though the trajectory changed from well to well, surface and downhole conditions remained relatively constant in terms of borehole and drill string geometry, stratigraphic sequence, mud rheology, drilling practices, MPD system, and rig type. Such relatively constant conditions created favorable circumstances for the comparison of conventional and MPD practices. Results show that MPD enabled the operator to avoid losses and achieve noticeable improvements in drilling efficiency and ECD management. In addition, there were noticeable improvements in MPD performance in terms of transition times and BHP control.

Accurate wellbore hydraulics simulations have been effective in assisting engineers to budget well time and materials, design and execute safe, optimum drilling operations. In this context, "accurate" is commonly understood as 0.1 pound per gallon (ppg) delta, or less, between measured and predicted equivalent circulating density (ECD). Extended-reach-drilling (ERD) wells have been gaining recent adoption due to advancements in drilling technologies. This type of well, by its geometrical nature, poses a challenge to pressure management, hole cleaning and wellbore stability. This increases the relevance of simulation aids. Simultaneously, the industry has seen challenges in achieving the accuracy levels required to model and simulate these wells appropriately. This work closes this gap. Several factors affect the accuracy of ECD predicting algorithms, including but not limited to: the wellbore geometry, pumping schedule, formation and fluid's temperature profiles, physical properties and drilling parameters. Offset information from five different wells was used as basis of investigation and verification. While opportunities for better simulation set-ups were found, it was also identified that refinements to the modeling assumptions were required. The prediction for these wells was enhanced by taking an existing drilling simulator and (1) improving the accuracy of pipe positioning estimation; (2) augmenting the understanding of the eccentric annular flow-field; and (3) including the effects of pipe rotation. This led to a superior determination of the downhole flow-regimes, pressure drops, cuttings transport efficiencies and constrictions due to cuttings beds accumulation. The presented enhanced simulator has been validated against 10+ additional wells. The prediction accuracy significantly improved where it previously lacked. Simultaneously, accuracy was maintained (or slightly improved) in conditions where it originally performed. For ERD wells as shallow as 5,000ft TVD and MD's in excess of 40,000ft, the original ECD predictions diverged as much as 1.5ppg (~400psi) from pressure-while-drilling (PWD). The achieved superior predictions were never above 0.1ppg (~26psi) delta when compared to PWD. Using this advanced simulator, engineers were able to tailor the appropriate rheology profiles to drill ERD wells at optimum performance and determine the best fluid systems’ configuration to achieve it. Operations were completed as planned and budgeted, without unexpected changes in drilling parameters This work presents an enhanced methodology to accurately model annular pressure drops in ERD wells. In addition to accounting for the appropriate flow-regime transitions in a downhole eccentric annulus, this method provides a "true north" as far as "tolerable" cuttings bed accumulation to maintain pressures within formation limits. By using this simulator, engineers were able to customize drilling fluids rheology profiles for minimum pressure loss gradients at performant sag resistant levels, and safely drill challenging ERD wells.

The conventional drilling approach of employing a drillstring and bottomhole assembly with bit for drilling purposes and eventually running a casing string includes several tripping operations that leave the wellbore open for extended periods of time as an alternative to drilling-with-casing operations where the bottomhole assembly is attached to the casing. This eliminates additional drillstring tripping as drilling and running casing are performed simultaneously. This type of application reduces the number of string trips needed to complete a section, thus saving operational time and associated costs. As the diameter of a casing is larger than a drillstring, this method generally increases the Equivalent Circulating Density (ECD) as pressure losses increase owing to the reduction of the open hole and casing string annulus area. Casing directional drilling operations provide a much narrower drilling window with regards to restrictions in the annulus thus increasing the chances of reaching fracture pressure compared with conventional drillstring operations. To negate the resultant increase in ECD, the rheological profile of the drilling fluid must be designed appropriately. This paper discusses a unique oil-based drilling fluid system weighted with treated micronized barite slurry (TMBS) that has more recently been developed and used successfully in the Eldfisk field of the Greater Ekofisk area, Norway. The drilling fluid system provides low viscosity and a relatively low flat rheology, reduced torque values, and superior sag stability, thus delivering a fluid of low ECD contribution, low-pressure peaks, very effective hydraulics performance and static stability. These exceptional fluid characteristics make the system an excellent solution for drilling sections where the difference between pore pressure and fracture pressure is narrow. This was particularly so in this case where the stability of the fluid from sag potential was crucial for the improved success of the drilling-with-casing operation. Any solids sag onto the latching tools or bottomhole assembly (BHA) with the casing could have caused interference. The system had been used before for differing hole conditions including managed-pressure drilling and extended-reach wells, in high-temperature, high-pressure (HTHP) wells, and now with competence in a casing directional drilling operation.

Stuck pipe incidents remain as one of the major problems in the drilling industry. The incidents will lead to expensive loss time in daily spread cost, bottom hole assembly cost, sidetracking cost as well as fishing cost. The Wells Augmented Stuck Pipe (WASP) Indicator, a state-of-the-art machine learning technology that seamlessly integrates with PETRONAS existing technologies, is introduced as the stuck pipe prevention detection system for the company. Historical real-time drilling data and stuck pipe incidents reports between 2007 and 2019 are used for the development of machine learning models. The models utilize key drilling parameters such as hookload and equivalent circulating density (ECD) to predict and analyze trends to detect any signature pattern anomalies for various stuck pipe events. The prediction and alarm are displayed in real-time monitoring software to trigger the operation team for prompt intervention. The WASP solution has demonstrated proven outcomes using historical and live well with high confidence in detecting stuck pipe incidents due to differential sticking, hole cleaning, and wellbore geometry. The WASP Indicator is envisaged to provide the company with cutting edge advantages in the industry. It is expected that the system will reduce the identification period and improve the reaction time of the monitoring specialists in recognizing the stuck pipe symptoms and highlighting potential incidents. The system is also bringing value to the company via non-productive time (NPT) cost avoidance and identification of early onset of various stuck pipe events based on distinct mechanisms. With the system, the existing portfolio value can be enhanced via setting dynamic trends and models into historical experiences context. The WASP Indicator is aspired to be the forefront innovation that will leap through the norm and lead the region in a greater plan of drilling automation system.

Four wells were successfully drilled and completed, but high drilling fluid densities (1.95 to 1.98 SG) were necessary to maintain wellbore stability in the overburden section immediately above the depleted reservoir. The estimated hydrostatic overbalance from the drilling fluid was approximately 800 bar (11,603 psi) higher than reservoir pressure. A wellbore strengthening technique was selected to seal the calculated 1500 μm fractures induced by these high pressures. This paper highlights the engineering, logistical, and operational challenges encountered while successfully drilling and completing such wells. Geomechanical data was initially acquired, including Young's modulus, Poisson's ratio, and minimum in-situ horizontal stress; and, together with the operational parameters [hole diameter and equivalent circulating density (ECD)], these data were used to estimate fracture width (1500 μm). Subsequently, a drilling fluid system was engineered and customized to seal such fractures, thereby strengthening the wellbore to help minimize losses in the reservoir. The solution was validated at two separate laboratories. Large particulate materials with a D50 of 600 to 2300 μm were used. Improvement opportunities during execution were captured for the next cycle. A total drilling fluid loss of 512 m3 during a 16-hour period was experienced in one well after a drilling liner packoff occurred, and fractures greater than 1500 μm were initiated; however, the liner was successfully cemented in place. The coarse particulate materials (600 to 2300 μm) were mobilized in 500 and 1000 kg bags to minimize deck space requirements on the rig and help facilitate ease of mixing. Rig mixing and pit agitation capacity were important for effective mixing of the fluid system. The application also provided the opportunity to align testing procedures and equipment between the field and laboratory. With increasing reservoir depletion, the potential exists for fracture width increases that can impact the particle size of materials necessary to effectively design a solution. Engineered particulate solutions provided a pathway for sourcing and procuring the necessary wellbore strengthening materials.

Weight material sag occurs during drilling operations when drilling fluids remain idle in the wellbore for time periods ranging from hours to several days at static or low-shear conditions. This paper presents a novel method of predicting real-time sag behavior in the wellbore. The method also accurately predicts the fluid mud weight collected at the surface as it is circulated out after a sag event, providing a significant advancement in drilling fluids engineering. Weight material sag is broadly viewed as the settling of barite particles in drilling fluids (primarily oil-based) under various mechanisms. Fluid composition (barite size/concentration and oil/water ratio) and fluid properties (i.e., rheology) influence the barite settling rate. The well geometry (i.e., inclination and diameter) also affects sag behavior. In addition, well operating conditions (i.e., temperature, pressure, and time for which fluid is uncirculated) also influence sag severity. A comprehensive computational approach was developed to model the sag behavior in wellbores using fluids composition/properties and wellbore geometry/conditions information. The wellbore sag model predicts information about the changing fluid composition along the wellbore depth as affected by sag, when the fluid in the well is under idle conditions (static or low shear). Specifically, for a wellbore section of a given inclination, the model provides quantitative density/rheology estimates of the barite-depleted zone at the top of the section and the barite-accumulated zone at the bottom. As the sag-affected fluid is circulated out after an idle period, the model also predicts the varied mud weight of the fluid collected at the surface and the corresponding transient bottomhole equivalent circulating density (ECD) as the circulation begins. The wellbore sag model predictions, especially the variation in the mud weight of the fluid collected at the surface after the sag event, were tested on several wells and fluid systems. The model provided good correlations between measured and predicted fluid density, typically less than 0.1 lbm/gal. The model accurately demonstrates how certain fluids show good sag resistance in some wells yet fail in some complex wells. The model also shows excellent sag resistance of certain specialized fluids in complex wells, which is in agreement with the field observation. A method to accurately determine real-time sag in the field has been a long-standing need. The successfully validated wellbore sag model, which captures the combined effect of fluids composition/properties and wellbore geometry/conditions, could serve as a useful tool for mud engineers to evaluate the sag behavior. It could also enable fast decision making at the rig site to optimize fluid formulations and operating conditions for sag management.

To maximize reservoir drainage and production volumes from a field in the United Arab Emirates (UAE), extremely long horizontal sections are necessary through the producing interval. Extended reach drilling (ERD) imposes significant requirements on the drilling operation and complicates the running of the production liner because of the long horizontal displacement. This paper details the design and field execution of an organophillic clay-free invert emulsion fluid (OCF-IEF) that met these ERD requirements and facilitated the longest liner run in the world. Successfully delivering a gauge wellbore with >20,442 ft of open hole at 90° inclination, followed by running and setting a production liner at target depth (TD), was not deemed achievable using a conventional invert emulsion fluid (IEF). A correctly designed fluid system was necessary to deliver success. The necessary fluid properties included a low rheology profile to minimize equivalent circulating density (ECD) to keep within the fracture gradient, long-term fluid stability, minimal formation damage risk, and low solids content to help minimize friction. A calcium-bromide brine-based low-solids OCF IEF was selected to meet these requirements. Through the use of this OCF-IEF system, the operator was able to achieve the well objectives, drilling one of the longest wells in the UAE, reaching a TD of 29,075 ft, including a record-breaking 20,442-ft openhole. The 8 1/2-in. reservoir section was drilled in 37 days, with only three trips necessary to change the bottomhole assembly (BHA). The average rate of penetration (ROP) varied between 70 to 100 ft/hr. The maximum ECD observed did not exceed the fracture gradient at any stage. Consequently, no downhole losses were experienced during the drilling phase. The engineered OCF-IEF achieved a low rheology profile, which minimized the contribution to annular pressure losses. The low rheology profile and low solids content in the IEF resulted in excellent fluid stability with no weighting material SAG. No losses were observed while running the liner, and no indications of tight spots were observed. Friction factors were low (between 0.15 and 0.25), and this facilitated the liner to be run without any issues. Total days on the well were 30 less than planned, which significantly saved both costs and rig time for the operator. The organophillic clays and organophillic lignites are replaced with various organic polymers to achieve different fluid behaviours (Strand et al. 2016). The novel polymer chemistry of this OCF-IEF together with a low solids content (attributed to using calcium-bromide base brine) resulted in desirable fluid properties that allowed the operator to extend limits, reach new depths, and break records to maximize production and increase revenue.

In today's increasingly complex well designs, often the range in drilling fluid densities required to prevent hole collapse without fracturing the wellbore, i.e. the safe drilling window, is narrow. This is often the case for wells having high angles of deviation, and is of particular concern in extended-reach drilling (ERD) wells. With increasing step-outs, the drilling equivalent circulating density (ECD) continues to climb with increasing measured depth (MD) while the true vertical depth (TVD) remains fairly constant. The net result can be that as horizontal departure lengths continue to increase, the drilling ECD violates the safe drilling window.In a recent study presented to the industry, the effects of changes in the water phase salinity (WPS) of invert emulsion drilling fluids (IEF) were investigated as a function of rock shear failure for two very different shales: a deepwater West Africa shale and a more-competent Oklahoma shale. After a 3-hr exposure time, the changes in rock strength with different WPS levels were measured directly and results were qualitatively consistent for the two shales.In this paper, the effect of changes in the WPS of IEF on the safe drilling window is demonstrated in an ERD drilling scenario. The modeled failure envelope is first examined using conventional elastic modeling. Poroelastic modeling is then used to show the effect of changes in the safe drilling window resulting from changes in pore pressure. As a further step, changes in the safe drilling window are next shown using porochemoelastic wellbore stability modeling, where the effects of invert emulsion drilling fluid chemistry coupled with changes in pore pressure are introduced. The results show that the safe drilling window can be changed with invert emulsion chemistry, and that there is much to be learned using more advanced poroelastic and porochemoelastic modeling techniques.

While drilling an 8.5 in. open hole in the Umm Shaif field, an unexpected fault was encountered across formation ARAB-D2, increasing losses from 15.0 to 40.0 bbl/hr. Initial losses were managed using mud lost-circulation material (LCM) pills; however, losses were observed again while running the liner. It was decided to cement the liner to secure the shoe, with the expectation of being required to perform a remedial operation. The liner was cemented with all precautions to help prevent further loss. By systematically introducing enhancements to the cementing and liner running practices and optimizing the fluid (cement/spacer) design using the latest technology fiber system in the spacer, it was possible to achieve the objective to control losses during the cementing operation. Additionally, securing the shoe and isolating the reservoir zone while preparing for a top-of-liner squeeze and liner perforation, if necessary, to squeeze cement in poorly isolated zones was achieved. Three-dimensional (3D) placement simulator software was used to model the flow rates and the equivalent circulating density (ECD) during the operation, and sensitivity runs were performed to observe worst-case scenarios at different loss rates to optimize volumes, rates, etc. Once the spacer crossed the loss zone, lost-circulation additives (composed of a blend of various additives) began bridging across the zone, enabling the cement slurry to reach the top of liner, where it circulated excess cement. The tagged hard cement above the top-of-liner log exhibited good isolation to the reservoir formation, no remedial operations were necessary for the shoe and top of liner, and no perforations were necessary. Spacer fluids are an environmentally acceptable blend of carefully selected materials, including coarse and tough LCM, fibers, and medium-sized, resilient angular materials. These fluid systems help mitigate losses when cementing across weak, unconsolidated, or fractured formations and carry materials with both high-pressure integrity and compressibility to help ensure tolerance to modifications in fracture size, caused by differential pressure fluctuations, without the materials being dislodged or allowing collapse. These materials are stable and insoluble in water. The spacer fluid system breaks the emulsion of oil-based drilling fluid, water wetting the casing pipe and the formation in preparation for cement bonding. Additionally, such materials resist intermingling of fluids at the interface in the fluid train.

Fields located in the southeastern area of the Neuquén Province of Argentina are widely recognized for their high formation pressures and related influxes while drilling the production section. Some of the challenges encountered when drilling using conventional techniques include kicks, losses, wellbore instability, and formation damage. They are also known for challenging cementing operations. These wellbore construction challenges can significantly impact non-productive time (NPT). Managed pressure cementing (MPC) has been implemented for recent wells after the target is achieved with managed pressure casing drilling (MPCD). This application enables the implementation of controlled bottomhole pressure (BHP) while cementing, without killing the well. Surface backpressure (SBP) is applied in accordance with the cementing pumping schedule, taking into account varying pump flow rates and fluid densities. In wells in which MPC was implemented, SBP was continuously applied to maintain the target equivalent circulating density (ECD) required for the cementing operation, avoiding expansion and gas migration. This paper describes the implementation, results, and behavior of the well while performing MPC. MPCD and MPC techniques have proven to be an effective combination to help optimize drilling time, improve bottomhole conditions, and reduce cementing costs. This paper includes lessons learned and recommendations to help enhance the implementation of these techniques and optimize the overall well construction phase to improve the performance of future wells.