THE EVOLUTION OF STABLE FOAM AS A DRILLING MEDIUM

1996 ◽  
Vol 36 (1) ◽  
pp. 557 ◽  
Author(s):  
J. Rovig
Keyword(s):  
Drilling Fluid ◽  
Pressure Control ◽  
Directional Drilling ◽  
Stable Foam ◽  
Lost Circulation ◽  
Drilling Performance ◽  
Underbalanced Drilling ◽  
Three Phase ◽  
Gravel Packing ◽  
Compressible Bubble

In the late 1960s Stable Foam was developed by Chevron USA as a lightweight circulation medium to clean out production sand in depleted (depleting) wells. In employing this new medium they found that Stable Foam's compressible bubble structure provided up to 10 times the carrying capacity of many common liquid based circulating fluids.These early successes led the industry to expand the use of Stable Foam from cased hole production clean outs to drill-ins, gravel packing, drilling in lost circulation zones, coil tubing, and today its utilisation as an Underbalanced Drilling fluid in depleted reservoirs.Through this evolution Stable Foam has had its successes and failures as well as unique operational concerns which has affected its consideration and utilisation.The following is a breakdown of the major hurdles which have been addressed and overcome, consequently positioning Stable Foam as a viable option for wider use in Underbalanced Drilling:Foam compatibility in water, oil, salt and high temperature environments.MWD and Directional Drilling performance with a compressible fluid.Surface pressure control while drilling.Surface separation and processing of a three phase well return fluid to provide a zero discharge closed loop circuit.

ERD Drilling Record Achieved in the Gulf of Thailand with an Outstanding Drilling Efficiency

2021 ◽  
Author(s):  
Manchukarn Naknaka ◽  
Trinh Dinh Phu ◽  
Khamawat Siritheerasas ◽  
Pattarapong Prasongtham ◽  
Feras Abu-Jafar ◽  
...  
Keyword(s):  
Chemical Elements ◽  
Drilling Fluid ◽  
Drill Pipe ◽  
Oil Field ◽  
Technology Selection ◽  
Low Flow ◽  
Gulf Of Thailand ◽  
Directional Drilling ◽  
Lost Circulation ◽  
The Gulf Of Thailand

Abstract The objective of this research is to describe the methodology used to drill the most extended reach well (ERD) in the Gulf of Thailand. The Jasmine field is a mature, sophisticated, oil field with many shallow reservoir targets that require a minimum 10,000ft horizontal displacement. As such, the main challenges faced, and the novel technology applied is described in detail by this research. The research is an example of successfully drilling a challenging well, safely and efficiently. The Jasmine C – Well X, is a 3-string design structure with an 11-3/4in top hole, an 8-1/2in intermediate section, and a 6-1/8in reservoir horizontal section. Well X was constructed by utilizing an existing platform well slot. The challenge involved drilling from the top hole to the kickoff point and directional drilling away from the casing stump of the existing well to avoid any collision with nearby wells emanating from the Jasmine C platform. The 8-1/2in hole section was the most important segment as it had to reach the landing point precisely in order to start the 6-1/8in section for GeoSteering in the reservoir section. The 8-1/2in section encountered three challenges that could affect drilling efficiency.Directional Drilling – The complexities of the well profile:The method involved making well inclination (INC) lower than 82deg in the tangent interval in order to reduce the well's tortuosity as much as possible.Hole condition – Hole cleaning and fluid losses control:The method involved the use of Low Toxicity Oil Based Mud (LTOBM) CaCO3 system, the chemical elements in the drilling fluid system could help to seal the high permeable zones.Drilling Engineering – Torque and Drag (T&D) control:The method taked into account the 7in casing run to the bottom of the hole, which the casing driven system did not allow for rotation The well was completed successfully without any additional trips. A Total Depth (TD) was of 13,052ftMD was achieved to reach reservoirs at 3,260ft TVDSS. It was therefore announced in 2019 as a new ERD record for Mubadala Thailand (ERD ratio = 3.26, Directional Difficulty Index (DDI) = 6.95). The top hole and 9-5/8in casing were set in the right depth. An 8-1/2in section was accomplished on the planned trajectory with an average on bottom Rate of Penetration (ROP) at 319 ft/hr. The 6-1/8in section was drilled by geosteering to achieve sub-surface objectives. A total of 2,143ft intervals inside the reservoir was successfully achieved. While drilling, lost circulation events occured, but the mud system was conditioned with Lost Circulation Materials (LCM). Therefore, drilling performance was unaffected. Moreover, the Bit's Total Flow Area (TFA) and Rotary steering systems (RSS) flow restrictor was configured to allow directional drilling at a very low Flow rate of 470gpm. Addition, 30 joints of 5-1/2in Heavy Weight Drill Pipe (HWDP) and 39 joints of 4in HWDP were added into the Bottom Hole Assembly (BHA) to transfer string weight to drill bitsand drill to well TD. As complexities of the well profile were fully aware, the casing was runned and minimized the open hole friction until the casing was deployed successfully. In the Gulf of Thailand, drilling the longest ERD well in a shallow True Vertical Depth (TVD) was clearly groundbreaking and entailed the successful management of the key operational challenges related to identification, job planning, design, technology selection, and implementation. This research illuminates the challenges and technical solutions of long ERD well and serves as an example of what can be achieved in the region and globally.

Wellbore Shielding Technique Increases Operative Window, Avoiding Formation Instability and Losses, Minimizing NPT, and Optimizing Drilling Operations in the Unconventional Plays

2021 ◽  
Author(s):  
Gaston Lopez ◽  
Gonzalo Vidal ◽  
Claus Hedegaard ◽  
Reinaldo Maldonado
Keyword(s):  
Drilling Fluid ◽  
Drilling Fluids ◽  
Wellbore Instability ◽  
Lost Circulation ◽  
Drilling Performance ◽  
Drilling Parameters ◽  
Vaca Muerta ◽  
Drilling Operations ◽  
Fracture Gradient ◽  
Vaca Muerta Formation

Abstract Losses, wellbore instability, and influxes during drillings operations in unconventional fields result from continuous reactivity to the drilling fluid causing instability in the microfractured limestone of the Quintuco Formation in Argentina. This volatile situation becomes more critical when drilling operations are navigating horizontally through the Vaca Muerta Formation, a bituminous marlstone with a higher density than the Quintuco Formation. Controlling drilling fluids invasion between the communicating microfractures and connecting pores helps to minimize seepage losses, total losses, wellbore fluid influxes, and instabilities, reducing the non-productive time (NPT) caused by these problems during drilling operations. The use of conventional sealants – like calcium carbonate, graphite, asphalt, and other bridging materials – does not guarantee problem-free drilling operations. Also, lost circulation material (LCM) is restricted because the MWD-LWD tools clearances are very narrow in these slim holes. The challenge is to generate a strong and resistant seal separating the drilling fluid and the formation. Using an ultra-low-invasion technology will increase the operative fracture gradient window, avoid fluid invasion to the formation, minimize losses, and stop the cycle of fluid invasion and instability, allowing operations to maintain the designed drilling parameters and objectives safely. The ultra-low-invasion wellbore shielding technology has been applied in various fields, resulting in significantly improved drilling efficiencies compared to offset wells. The operator has benefited from the minimization of drilling fluids costs and optimization in drilling operations, including reducing the volume of oil-based drilling fluids used per well, fewer casing sections, and fewer requirements for cementing intervals to solve lost circulation problems. This paper will discuss the design of the ultra-low-invasion technology in an oil-based drilling fluid, the strategy for determining the technical limits for application, the evaluation of the operative window with an increase in the fracture gradient, the optimized drilling performance, and reduction in costs, including the elimination of NPT caused by wellbore instability.

Application of Real-Time Field Data to Optimize Drilling Hydraulics Using Neural Network Approach

2015 ◽  
Vol 137 (6) ◽  
Author(s):  
Yanfang Wang ◽  
Saeed Salehi
Keyword(s):  
Neural Network ◽  
Real Time ◽  
Field Data ◽  
Ann Model ◽  
Time Data ◽  
Neural Network Approach ◽  
Lost Circulation ◽  
Drilling Performance ◽  
Artificial Neural Network Ann ◽  
Pump Pressure

Real-time drilling optimization improves drilling performance by providing early warnings in operation Mud hydraulics is a key aspect of drilling that can be optimized by access to real-time data. Different from the investigated references, reliable prediction of pump pressure provides an early warning of circulation problems, washout, lost circulation, underground blowout, and kicks. This will help the driller to make necessary corrections to mitigate potential problems. In this study, an artificial neural network (ANN) model to predict hydraulics was implemented through the fitting tool of matlab. Following the determination of the optimum model, the sensitivity analysis of input parameters on the created model was investigated by using forward regression method. Next, the remaining data from the selected well samples was applied for simulation to verify the quality of the developed model. The novelty is this paper is validation of computer models with actual field data collected from an operator in LA. The simulation result was promising as compared with collected field data. This model can accurately predict pump pressure versus depth in analogous formations. The result of this work shows the potential of the approach developed in this work based on NN models for predicting real-time drilling hydraulics.

Drilling Automation – Benefits of the New Drilling Model

2021 ◽  
Author(s):  
Jorge Heredia ◽  
Jan Egil Tengesdal ◽  
Rune Hobberstad ◽  
Julien Marck ◽  
Harald Kleivenes ◽  
...  
Keyword(s):  
Conventional Method ◽  
Three Dimensional ◽  
Cost Savings ◽  
Work Force ◽  
Directional Drilling ◽  
Well Performance ◽  
Human Errors ◽  
Drilling Performance ◽  
Friction Factors ◽  
Remote Operations

Abstract A pilot program for automated directional drilling was implemented as a part of the roll out plan in Norway to drill three dimensional wells in an automated mode, where steering commands were carried out automatically by the automation platform. The rollout plan also targeted the use of remote operations to allow personnel to be relocated from the rig location into remote drilling centers. The goal of the program was to optimize the directional drilling performance by assessing the benefits of automation using the latest rotary steerable system technologies and machine learning smart algorithms to predict and manipulated the BHA performance, as well as the ability to predict the best drilling parameters for hole cleaning. The automation was implemented on three different rigs and the data was compared with the drilling performance from the last two years, with three dimensional wells drilled in the conventional method. The main benefits between drilling wells in the conventional method versus drilling wells with the new drilling automation model include the following. Reduce the overall cost per meter –  Improve the rate of penetration –  Improve running casings Consistence process adherence –  Reduce human errors –  Reduce POB without sacrificing lost of technical experience Optimize workforce resources –  Allows continuity of service (COVID-19 restrictions) Drilling automation can drill smoother wells by reducing the friction factors and tortuosity. This is translated in direct cost savings per meter and reduction in the overall well delivery time, with the advantage of performing the execution and monitoring of the well performance remotely. This new drilling model open the door of new opportunities, especially for the challenges where the work force resources, and drilling performance is a priority for the operations.

Intelligent Rotary Steerable System, Coupled with an Instrumented Bit, Delivers Section Plan in Deepwater GOM Project

2021 ◽  
Author(s):  
John Snyder ◽  
Graeme Salmon
Keyword(s):  
Intelligent Systems ◽  
Systems Approach ◽  
Polycrystalline Diamond ◽  
Cost Effective ◽  
Structure Design ◽  
Directional Drilling ◽  
Steering Control ◽  
Efficient System ◽  
Drilling Performance ◽  
Downhole Tool

Abstract The challenging offshore drilling environment has increased the need for cost-effective operations to deliver accurate well placement, high borehole quality, and shoe-to-shoe drilling performance. As well construction complexity continues to develop, the need for an improved systems approach to delivering integrated performance is critical. Complex bottom hole assemblies (BHA) used in deepwater operations will include additional sensors and capabilities than in the past. These BHAs consist of multiple cutting structures (bit/reamer), gamma, resistivity, density, porosity, sonic, formation pressure testing/sampling capabilities, as well as drilling dynamics systems and onboard diagnostic sensors. Rock cutting structure design primarily relied on data capture at the surface. An instrumented sensor package within the drill bit provides dynamic measurements allowing for better understanding of BHA performance, creating a more efficient system for all drilling conditions. The addition of intelligent systems that monitor and control these complex BHAs, makes it possible to implement autonomous steering of directional drilling assemblies in the offshore environment. In the Deepwater Gulf of Mexico (GOM), this case study documents the introduction of a new automated drilling service and Intelligent Rotary Steerable System (iRSS) with an instrumented bit. Utilizing these complex BHAs, the system can provide real-time (RT) steering decisions automatically given the downhole tool configuration, planned well path, and RT sensor information received. The 6-3/4-inch nominal diameter system, coupled with the instrumented bit, successfully completed the first 5,400-foot (1,650m) section while enlarging the 8-1/2-inch (216mm) borehole to 9-7/8 inches (250mm). The system delivered a high-quality wellbore with low tortuosity and minimal vibration, while keeping to the planned well path. The system achieved all performance objectives and captured dynamic drilling responses for use in an additional applications. This fast sampling iRSS maintains continuous and faster steering control at high rates of penetration (ROP) providing accurate well path directional control. The system-matched polycrystalline diamond (PDC) bit is engineered to deliver greater side cutting efficiency with enhanced cutting structure improving the iRSS performance. Included within the bit is an instrumentation package that tracks drilling dynamics at the bit. The bit dynamics data is then used to improve bit designs and optimize drilling parameters.

Machine-Learning for the Prediction of Lost Circulation Events - Time Series Analysis and Model Evaluation

2021 ◽  
Author(s):  
Arturo Magana-Mora ◽  
Mohammad AlJubran ◽  
Jothibasu Ramasamy ◽  
Mohammed AlBassam ◽  
Chinthaka Gooneratne ◽  
...  
Keyword(s):  
Machine Learning ◽  
Time Series ◽  
Real Time ◽  
Large Scale ◽  
Model Comparison ◽  
Drilling Fluid ◽  
Sensor Data ◽  
False Alarms ◽  
Suitable Model ◽  
Lost Circulation

Abstract Objective/Scope. Lost circulation events (LCEs) are among the top causes for drilling nonproductive time (NPT). The presence of natural fractures and vugular formations causes loss of drilling fluid circulation. Drilling depleted zones with incorrect mud weights can also lead to drilling induced losses. LCEs can also develop into additional drilling hazards, such as stuck pipe incidents, kicks, and blowouts. An LCE is traditionally diagnosed only when there is a reduction in mud volume in mud pits in the case of moderate losses or reduction of mud column in the annulus in total losses. Using machine learning (ML) for predicting the presence of a loss zone and the estimation of fracture parameters ahead is very beneficial as it can immediately alert the drilling crew in order for them to take the required actions to mitigate or cure LCEs. Methods, Procedures, Process. Although different computational methods have been proposed for the prediction of LCEs, there is a need to further improve the models and reduce the number of false alarms. Robust and generalizable ML models require a sufficiently large amount of data that captures the different parameters and scenarios representing an LCE. For this, we derived a framework that automatically searches through historical data, locates LCEs, and extracts the surface drilling and rheology parameters surrounding such events. Results, Observations, and Conclusions. We derived different ML models utilizing various algorithms and evaluated them using the data-split technique at the level of wells to find the most suitable model for the prediction of an LCE. From the model comparison, random forest classifier achieved the best results and successfully predicted LCEs before they occurred. The developed LCE model is designed to be implemented in the real-time drilling portal as an aid to the drilling engineers and the rig crew to minimize or avoid NPT. Novel/Additive Information. The main contribution of this study is the analysis of real-time surface drilling parameters and sensor data to predict an LCE from a statistically representative number of wells. The large-scale analysis of several wells that appropriately describe the different conditions before an LCE is critical for avoiding model undertraining or lack of model generalization. Finally, we formulated the prediction of LCEs as a time-series problem and considered parameter trends to accurately determine the early signs of LCEs.

Study of the Cause of Lost Circulation while Drilling Fractured Carbonates

2021 ◽  
Author(s):  
Alexey Ruzhnikov
Keyword(s):  
Success Rate ◽  
Drilling Fluid ◽  
Circulation Zone ◽  
Lost Circulation ◽  
Carbonate Formation ◽  
New Information ◽  
Fractured Carbonate ◽  
Long Time ◽  
The Difference ◽  
Fractured Carbonates

Abstract Fractured carbonate formations are prone to lost circulation, which affects the well construction process and has longtime effect on well integrity. Depending on the nature of losses (either induced or related to local dissolutions) the success rate is different when the induced losses can be cured with a high chance, and the one related to dissolutions may take a long time, and despite multiple attempts, the success rate is normally low. To have a better understanding of the complete losses across the fractured carbonates, a series of studies were initiated. First, to understand the strength of the loss zone, the fracture closing pressure was evaluated studying the fluid level in the annulus and back-calculating the effect of drilling fluid density. Second, the formation properties across the loss circulation zones were studied using microresistivity images, dip data, and imaging of fluid-saturated porous media. The results of the studies brought a lot of new information and explained some previous mysteries. The formation strength across the lost circulation zone was measured, and it was confirmed that it remains constant despite other changes of the well construction parameters. Additionally, it was confirmed that the carbonates are naturally highly fractured, having over 900 fractures along the wellbore. The loss circulation zone was characterized, and it was confirmed that the losses are not related to the fractures but rather to the karst, dissolution, and megafractures. The size and dip of the fractures were identified, and it was proven the possibility to treat them with conventional materials. However, the size of identified megafractures and karst zones exceeding the fractures by 10 times in true vertical depth, and in horizontal wells the difference is even higher due to measured depth. This new information helps to explain the previous unsuccessful attempts with the conventional lost circulation materials. The manuscript provides new information on the fractured carbonate formation characterization not available previously in the literature. It allows to align the subsurface and drilling visions regarding the nature of the losses and further develop the curing mechanisms.

scholarly journals Application of Artificial Intelligence Techniques in Predicting the Lost Circulation Zones Using Drilling Sensors

2020 ◽  
Vol 2020 ◽  
pp. 1-18
Author(s):  
Abdulmalek Ahmed ◽  
Salaheldin Elkatatny ◽  
Abdulwahab Ali ◽  
Mahmoud Abughaban ◽  
Abdulazeez Abdulraheem
Keyword(s):  
Artificial Intelligence ◽  
Real Time ◽  
Drilling Fluid ◽  
Confusion Matrix ◽  
High Accuracy ◽  
Functional Networks ◽  
Lost Circulation ◽  
Drilling Parameters ◽  
High Pressure High Temperature ◽  
Drilling Cost

Drilling a high-pressure, high-temperature (HPHT) well involves many difficulties and challenges. One of the greatest difficulties is the loss of circulation. Almost 40% of the drilling cost is attributed to the drilling fluid, so the loss of the fluid considerably increases the total drilling cost. There are several approaches to avoid loss of return; one of these approaches is preventing the occurrence of the losses by identifying the lost circulation zones. Most of these approaches are difficult to apply due to some constraints in the field. The purpose of this work is to apply three artificial intelligence (AI) techniques, namely, functional networks (FN), artificial neural networks (ANN), and fuzzy logic (FL), to identify the lost circulation zones. Real-time surface drilling parameters of three wells were obtained using real-time drilling sensors. Well A was utilized for training and testing the three developed AI models, whereas Well B and Well C were utilized to validate them. High accuracy was achieved by the three AI models based on the root mean square error (RMSE), confusion matrix, and correlation coefficient (R). All the AI models identified the lost circulation zones in Well A with high accuracy where the R is more than 0.98 and RMSE is less than 0.09. ANN is the most accurate model with R=0.99 and RMSE=0.05. An ANN was able to predict the lost circulation zones in the unseen Well B and Well C with R=0.946 and RMSE=0.165 and R=0.952 and RMSE=0.155, respectively.

scholarly journals Laboratory Study on Core Fracturing Simulations for Wellbore Strengthening

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-18 ◽  
Author(s):  
Biao Ma ◽  
Xiaolin Pu ◽  
Zhengguo Zhao ◽  
Hao Wang ◽  
Wenxin Dong
Keyword(s):  
Bearing Capacity ◽  
Laboratory Study ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Lost Circulation ◽  
The Core ◽  
Fracture Pressure ◽  
Fluid Systems ◽  
Fracturing Process ◽  
Wellbore Strengthening

The lost circulation in a formation is one of the most complicated problems that have existed in drilling engineering for a long time. The key to solving the loss of drilling fluid circulation is to improve the pressure-bearing capacity of the formation. The tendency is to improve the formation pressure-bearing capacity with drilling fluid technology for strengthening the wellbore, either to the low fracture pressure of the formation or to that of the naturally fractured formation. Therefore, a laboratory study focused on core fracturing simulations for the strengthening of wellbores was conducted with self-developed fracture experiment equipment. Experiments were performed to determine the effect of the gradation of plugging materials, kinds of plugging materials, and drilling fluid systems. The results showed that fracture pressure in the presence of drilling fluid was significantly higher than that in the presence of water. The kinds and gradation of drilling fluids had obvious effects on the core fracturing process. In addition, different drilling fluid systems had different effects on the core fracture process. In the same case, the core fracture pressure in the presence of oil-based drilling fluid was less than that in the presence of water-based drilling fluid.

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