Predictive Data Mining Techniques for Mud Losses Mitigation

Lost circulation is a complicated problem to be banned or combatted during the drilling operations. Mud losses remedies are extensively used to stop or mitigate losses using remedial methods or to prevent mud losses using proactive measures. Lost circulation presents a lot of big challenges during drilling. To address these problems, a number of methods/techniques have evolved over the years. The Rumaila field in Iraq is one of the largest oilfields in the world. Wells drilled in this field are highly susceptible to lost circulation problems when drilling through the Hartha formation. Lost circulation events range from seepage losses to complete loss of the borehole and are a critical issue in field development. This paper describes a study of the lost circulation events for more than 300 wells drilled in the Rumaila field. Lost circulation events were extracted from daily drilling reports, final drilling reports, and technical reports. Key drilling parameters (e.g. ROP, SPM, RPM, WOB, bit type) and mud properties (e.g. mud weight, yield point, gel strength) at the time of each event were recorded along with the lost circulation remedies attempted, and the outcome of those remedies. These data have been analyzed to determine the best ranges of the key drilling parameters that have the greatest chance of mitigating lost circulation in the Hartha formation. Practical field information from the Rumaila field and range of sources have been reviewed and summarized to develop an integrated methodology and flowchart for handling lost circulation events in this formation. In a related development, this paper will be extended work along with previous comprehensive statistical study and sensitivity analysis models about the Hartha formation to obtain the best field procedures for avoiding or minimizing lost circulation events in the Hartha formation. Proactive approaches have been made prior entering the Hartha formation to prevent or mitigate the occurrence of lost circulation. A unique statistical work, primitive mechanisms, typical drilling fluid properties and recommended operational drilling parameters have been evaluated to use during drilling the Hartha formation. In addition, corrective actions have been determined for each kind of the mud losses to provide effective remedies, minimize non-productive time, and reduce cost. Lost circulation strategy to the Hartha formation has been summarized depending on statistical work and economic analysis evaluation to determine the most successful remedies for each type of the losses. These treatments are classified by relying on the mud losses classifications in order to avoid unwanted consequences due to inappropriate actions. This study provides a typical compilation of information regarding traditional approaches and the latest approaches to lost circulation control. In addition, the work attempts to provide useful guidelines or references for both situations in terms preventive measures, remedial methods, and analytical economic study.

Recently, artificial intelligence has gain popularity in the drilling industry since more wells are drilled in hostile environments. One of the most difficult problems have been encountering the drilling operation is the problem of lost circulation. The complexity of the lost circulation problem is due to the interaction between the parameters that are causing this issue. The aim of this work is to create artificial intelligence models to predict lost circulation, equivalent circulation density (ECD), and rate of pentation (ROP) prior to drilling for naturally fractured formations. Lost circulation events from 500 wells were collected and analyzed to comprehend the impact of each drilling parameter on lost circulation. The data were cleaned and outliers were removed. Partial least square (PLS), a supervised machine learning algorithm, was utilized to create three models to estimate mud losses, ECD, and ROP before drilling. The models went through a cross-validation process to validate them. In addition, the models were tested with new data that were not used in the process of creating the models. The results showed that the three models can predict mud losses, ECD, and ROP within a reasonable margin of error. Testing the models with new data of 30 wells drilled showed that the models' predictions closely track the actual values from the real data. Moreover, the new models were compared with previously developed models for naturally fractured formations. The new models showed better predictions for the actual values than the previously developed models, suggesting the ability of the new models to predict mud losses, ECD, and ROP within an acceptable error. In addition, a 10% sensitivity analysis was conducted for all models to quantify and understand the effect of each parameter on every model. Mud weight (MW) had the highest impact on the ECD and mud losses models revealing that in order to minimize mud losses and ECD, the first action should be trying to use as low MW as possible. On the other hand, weight on bit (WOB) showed the highest positive influence on the ROP model and total flow area (TFA) of the nozzles showed the highest negative impact on the ROP model. Thus, the models developed in this study can be used to regulate the drilling parameters to minimize mud losses. The methodology used in this study to develop estimation models for mud losses, ECD, and ROP can be applied to create predictive models in other formations if the required data are available.

Lost circulation costs are a significant expense in drilling oil and gas wells. Drilling anywhere in the Rumaila field, one the world’s largest oilfields, requires penetrating the Dammam formation, which is notorious for lost circulation issues and thus a great source of information on lost circulation events. This paper presents a new, more precise model to predict lost circulation volumes, equivalent circulation density (ECD), and rate of penetration (ROP) in the Dammam formation. A larger data set, more systematic statistical approach, and a machine-learning algorithm have produced statistical models that give a better prediction of the lost circulation volumes, ECD, and ROP than the previous models for events. This paper presents the new model, validates the key elements impacting lost circulation in the Dammam formation, and compares the predicted outcomes to those from the older model. The work previously presented by Al-Hameedi et al. (http://www.onepetro.org, 2017a; http://www.AADE.org, 2017b) provided a platform for predicting the severity of lost circulation incidents in the Dammam formation. Using the new models, the predictions closely track actual field incidents of lost circulation. When new lost circulation events were compared with predictions from the old and new models, the new model presented a much tighter prediction of events. Three equations for optimizing operations were developed from these models focusing on the elements that have the highest degree of impact. The total flow area of the nozzles was determined to be a significant factor in the ROP model indicating that nozzle size should be chosen carefully to achieve optimal ROP. Good modeling of projected lost circulation events can assist in evaluating the effectiveness of new treatments for lost circulation. The Dammam formation is a significant source of lost circulation in a major oilfield and warrants evaluation of the effectiveness of lost circulation treatments. These techniques can be applied to other fields and formations to better understand the economic impact of lost circulation and evaluate the effectiveness of various lost circulation mitigation efforts.

Lost circulation is a significant challenge in drilling operations, leading to fluid losses, increased non-productive time, and well instability. This paper develops a predictive model to quantify lost circulation in the Al Jeribe Formation in the Al-Omar field, one of the largest oilfields in the Middle East. Lost circulation is especially prevalent when drilling through the Al Jeribe formation due to the presence of vugs and caves. However, current models for predicting lost circulation often suffer from limited accuracy and efficiency due to the complexity of geological formations and the variability of drilling conditions, leading to unreliable predictions in challenging environments. This research aims to overcome these limitations by developing a more accurate and efficient predictive model tailored to the Al Jeribe Formation, providing valuable insights to mitigate fluid loss and improve drilling efficiency. This paper introduces a novel predictive model for lost circulation in the Al Jeribe Formation, utilizing artificial neural networks (ANNs) trained on extensive field data from over 100 wells. The model incorporates key drilling parameters such as mud weight (MW), yield point (Yp), equivalent circulation density (ECD), rate of penetration (ROP), revolutions per minute (RPM), strokes per minute (SPM), Plastic viscosity (PV), and weight on bit (WOB) as input parameters. The ANN achieved excellent predictive performance, with Training R2 = 0.99 and Testing R2 = 0.99. Error metrics also confirmed strong generalization, with RMSE = 1.70% (training) and 1.40% (testing), and AAPE = 11.0% (training) and 10.2% (testing). In addition, the model identified the most critical parameters influencing lost circulation and provided optimized parameter ranges to mitigate fluid loss during drilling operations. This study focuses on lost circulation prediction in the Al Jeribe Formation, identifying key drilling parameters and providing optimized ranges to reduce losses and improve wellbore stability. It offers insights not covered in previous research, specifically targeting the Al Jeribe Formation. The model predicts lost circulation and suggests practical adjustments to drilling parameter values. The findings are expected to enhance drilling efficiency and minimize downtime in the Al-Omar field. This methodology can also be applied to similar geological formations worldwide to reduce lost circulation in oil fields.

For the period different drilling campaigns took place at the Tapi and Auca Fields, Ecuador. A downhole monitoring pressure tool helped identify some important pressure behaviors and scenarios. The ECD monitoring led to better wellbore cleaning, drop of mud weight detection not detected on surface and improvement of drilling operation times by deciding whether it was necessary to make short trips or not, based on the acquired data. All the gathered data allowed the creation of a database that will become the baseline to improve future drilling projects in those fields. The tool uses a quartz crystal type transducer that grants high resolution and accurate readings in real time and memory of annular pressures and bore pressures. Additionally, ECD (Equivalent Circulating Density) and ESD (Equivalent Static Density) measurements are calculated and this last one also defines an inherent value of the EMW (Equivalent Mud Weight). The tracing of these values show the performance of the drilling fluid and an ECD working frame could be defined to ensure effective cleaning of the well. In order to understand ECD, external factors affecting its behavior need to be denoted such as flow patterns, ROP or drilling fluid properties. Additionally, the applications of pressure records when performing FIT, CIT or LOT are explained. Different scenarios of how the data was analyzed, interpreted and the decisions taken during the operations are shown in this paper.

It is recognized that there is no single solution to lost circulation, and most treatment and trial-and-error. However, the screening guide presents a high-level ‘go to’ document with coherent guidelines, which engineers can utilize in making decisions regarding lost circulation treatments in major oil fields. The aim of this work is to describe how mud engineers can use the decision tree analysis (DTA) to evaluate and select the best treatments path for mitigating mud losses. Lost circulation events of Southern Iraq oil fields were statistically analyzed to determine treatment effectiveness. Also, the cost of each treatment, as well as the NPT that is associated with the treatment, is considered in this study. Data from over 1000 wells were gathered from various sources and reports; the treatments were classified by scenario -partial, severe, and complete losses - as well as cost, efficiency, and formation types. This paper is developed based on probabilities, expected monetary value (EMV), and decision tree analysis (DTA) to recommend the best-lost circulation treatments path for each type of losses. Traditionally, lost circulation in Southern Iraq area has been treated in a multitude of ways without consistent methodology. This analysis identifies and ranks the most effective treatments to create a "best" method/product recommendation and a flowchart suggesting additional measures in treating losses to optimize success and reduce overall cost and NPT. This paper presents the best treatment for each scenario - partial loss, severe losses and complete losses - both for product selection and engineering. This paper utilizes probability and economics in the decision-making process. This is the first study that considers a detailed probability and cost to treat the lost circulation problem. Thousands of treatment scenarios for each type of losses are conducted, and the EMVs for all scenarios are calculated. For each type of losses, the lowest EMV treatment strategy- that is practically applicable in the field and makes sense- is selected to be used to treat each type of losses to minimize NPT and cost. If the losses didn't stop after utilizing the proposed treatment strategies, it is recommended to use liner hanger to isolate the losses zone and then continue drilling. One challenge in drilling wells in Southern Iraq oil fields is the inconsistency of approaches to the lost circulation problem. Therefore, the result of this data analysis provides a path forward for Southern Iraq area lost circulation events and suggests probable methods that can be used in similar formations globally. Additionally, the methodology can be adapted to studying other types of formations and drilling challenges have the same geological properties in any major oil field.

Hydrocarbon-bearing reservoirs in a mature field, offshore Sarawak, Malaysia, contains multiple reservoir cycles interbedded with weak shale and coal formations. Years of production from these reservoirs caused significant pressure depletion, as well as reduced fracture gradient and a narrower drilling mud weight window. An improperly weighted mud may induce wellbore instability in weaker, but normally pressured, formations or mud losses in the heavily depleted reservoirs. Globally, mud losses are considered the most expensive well control operation incidents. Earlier drilling campaigns in ths field encountered numerous wellbore instability incidents; hence, a study was conducted to develop an understanding of the drilling issues and assess the stability of the heavily depleted reservoirs. Collaboration between the drilling and geomechanics teams facilitated better understanding of the stability challenges and helped in mitigating risk related to wellbore instability. A field scale geomechanical model was developed and validated using data from exploration and development wells from different phases of drilling in the study area. The stress path factor (SPF), which determines the reduction in fracture gradient with pore pressure depletion is crucial for defining drilling mud windows, is difficult to constrain in the absence of measured formation fracturing data in virgin and depleted reservoirs. A mud loss event in the depleted zone from a recent drilled well and regional information were used to estimate the range of SPF in the study area. Recorded bottom hole pressures from pressure while drilling (PWD) data suggested that the maximum equivalent circulating density (ECD) recorded was close or within the depleted section. The loss event was associated with reduced fracture gradient due to depletion from its pre-depleted range. This paper describes how geomechanical evaluation with effective well drilling practices and fit for purpose-drilling fluids have helped drilling through depleted reservoirs with ECD management. At the end, it shows a comparison of the predrill wellbore stability mud weight estimates with the actual mud weights used to successfully drill and complete the planned wells.

Multilateral drilling technology is difficult and risky, especially if the target is a naturally fractured carbonate abnormally pressured formation. Even drilling of simple wells in such formations risks severe mud losses and loss of circulation, which is why most of these wells have not been drilled to total depth (TD). Yurubcheno-Tokhomskoe oil field, located in west Siberia, is a notable example where such problems are observed. To reduce mud losses and make it possible to reach the TD, multiphase managed-pressure-while-drilling (MPD) technology was applied in Yurubcheno-Tokhomskoe field, and the results exceeded all expectations. MPD is an adaptive drilling process used to dynamically control the bottomhole pressure (BHP), either with friction pressure losses or with applied surface backpressure. It requires thorough planning of the entire preparation and drilling phases. Implementation of MPD gives a proven technological advantage in these cases where, even though reducing mud weight helps to manage the equivalent circulating density (ECD) while circulating, during static periods, BHP is lower than pore pressure, which leads to well control events. Pumping lost circulation material (LCM) does not solve the losses problem; rather, the addition of LCM increases formation damage and affects well productivity. The first application of multiphase MPD technology in Russia was in 2016 at Yurubcheno-Tokhomskoe field for drilling of a simple horizontal well. Compared to conventional drilling, multiphase MPD enabled reducing mud losses by 80% and increasing average rate of penetration (ROP) by 40%. Furthermore, no LCM pills or oil-water mixture was applied for handling mud losses, which positively affected formation production properties. The initial production potential of wells drilled with MPD was 65 to 180% more than expected. In September 2017, multiphase MPD technology was applied for drilling first horizontal multilateral well at Yurubcheno-Tokhomskoe. It enabled drilling all six planned laterals, of which the overall length was 2571 m. Furthermore, compared to a conventionally drilled multilateral well at this field, mud losses were reduced by approximately 80% (1619 m3 instead of 9354 m3) and average ROP was increased. It is also important to note that no LCM or oil-water mixture was used during drilling this well. No lost circulation or well control incident was incurred, which materially reduced net drilling days. Successful drilling of the first multiphase MPD multilateral well showed the high potential of this technique for drilling 4-in. horizontal sections in highly fractured carbonate formations. One main and five laterals were drilled. Each of drilled laterals required an individualized approach due to the completely different behavior of the wells. Such results open new horizons for drilling and completion of complicated wells in Yurubcheno-Tokhomskoe oil field. Because of this project, it was decided to drill more complicated multilateral wells with MPD technology in future.

There are multiple mechanisms that may drive a lost circulation event while drilling a well. Efficiently dealing with those events requires that the operations team quickly get an understanding of subsurface conditions that caused the event. Globally, some lost circulation events are cured by basic lost circulation materials (LCM) / bridging, while others fail to be cured even after days of attempts with lost circulation cement plugs (LCP) and novel materials. The aperture of the lost circulation zone (LCZ) remains unknow in most of the cases unless open hole logs ran to identify it. The standard approach to cure the losses is to start with less aggressive materials followed by more aggressive, and the curing based on the field practices, rather being linked to the potential opening of LCZs. The manuscript will investigate the hypothesis that the lost circulation events related to penetration of large, connected, open cavities (karsts) can be characterized, and those large open cavities can be identified in near-real time by analyzing the dynamic drilling parameters with help of Machine Learning. There are different mechanisms that are driving the lost circulation events. Within the same formation some of lost circulation zones can be easily cured with LCM/LCP, others require more effort and time and may be uncurable. The invention proposes a workflow and an algorithm to detect from dynamic drilling parameters what is the likely mechanism at play, and whether the lost zone is curable. Large fracture and dissolution cavities will have different mechanical properties, and drilling through those features will require significantly less energy than through a competent rock formation. They are also discrete events within a geological formation, and therefore will have outlier mechanical properties within a formation. The test was performed in over 300 wells, across different lost circulation zones (some wells had several zones). The developed algorithm was incorporated into the software in Real-time Monitoring center, allowing near real-time estimation of the aperture to decide regarding the LCM or LCP to be used. The results showed that in upper sections the multiple lost circulations zones presented with different thickness. The majority of the identified karsts are within range of 2-to-8 ft, with some going over 10 ft. In the deeper formations LCZ with the aperture of 4-to-9 ft were identified. The interesting part was related to the significant difference between MSE while drilling competent formation and the lost circulation zone, when MSE values were dropping almost to zero. The manuscript provides the novel approach allowing to use machine learning to identify the aperture of the lost circulation based on the real time parameters. The proposed approach can be used at any drilling project worldwide.

BP Egypt used a subsea pumping system on the Rahamat 1 well so that engineered mud could be used to drill the surface hole with returns to the Constellation II rig bypassing a large air gap. This was the first use of Riserless Mud Recovery (RMR) on a jack-up. It allowed 26" surface hole to be drilled and 22" surface casing to be set at 3755ft (1144m) Below Mud Line (BML) without major problems. Firm sand prevents a 30" conductor being driven deeper than 167ft (51m) BML. The rig has a large, 130ft (40m), air gap and the water depth is just 62ft (19m). The result is a conductor shoe that can only support a column of 7ppg (0.8SG) fluid back to the rig. Inhibited mud, minimum weight 9.4ppg (1.13SG), was needed to control the formations. Seabed returns were unacceptable for environmental and mud supply reasons. RMR installation / retrieval was mainly done off the critical path and did not need an ROV. The system took returns from the conductor at sea level and pumped mud with cuttings back to the rig. Mud was re-circulated after treatment. This allowed good control of the mud properties. Equivalent Circulating Density (ECD) pressure was reduced by (a) 3.5ppg (0.4SG) at the casing shoe and (b) 0.3ppg (0.04SG) at section TD compared to a full column of mud back to the rig. Mud losses in coarse sands were controlled by adding Lost Circulation Material (LCM) and fluid loss control material. The 26" hole was drilled to the planned depth. 22" casing was run and cemented while controlling the fluid level in the annulus (and therefore downhole pressure) with RMR. No losses were seen during these operations. RMR allowed surface hole to be drilled with mud and returns to the rig because RMR removed the effect of the 130ft air gap. The alternative well design needed an additional liner, taking 20 days and costing US$10million (based on previous well). The additional advantage was that engineered mud was used throughout the surface hole resulting in greater hole stability.

Formation collapse gradient is an important parameter for well design and drilling mud selection, especially in a field with history of wellbore instability problems. In modern well design, this gradient is easily neglected since its tendency to be lower than pore pressure gradient. However, some field studies in Indonesia showed that the collapse gradient may be higher than the pore pressure gradient which will result in an unstable well if the bottom hole pressure (BHP) is not well addressed. In the event of formation collapse, the common drilling practice is to increase the mud weight (MW) being used to a level above the collapse gradient which is time consuming and very rigid operation. Meanwhile, Manage Pressure Drilling (MPD) offers a relatively more dynamic wellbore pressure control by adjusting the surface back pressure (SBP) applied to the annulus for a given MW. Instead of shifting the MW or changing drilling parameters, MPD provide adjustment to the required equivalent circulating density (ECD) or equivalent static density (ESD) based on formation collapse gradient. Additionally, in the event of mud losses due to high ECD/ESD, MPD technique simply lowers the SBP to decrease the BHP without the need to lower the MW. This paper will utilize hydraulic simulation software to model the drilling window, considering not only pore and fracture pressure gradient, but also involving collapse gradient to optimize recommended MPD parameters including MW and SBP when drilling, pipe connection, and completing the well.

Top-hole drilling in the Caspian Sea has historically been very problematic: severe drilling problems are normal when drilling the 26" top-hole sections conventionally – an unconsolidated, over-pressurized sand stratum in the Shah Deniz Field has been one source of these problems. A narrow pore/fracture pressure window, shallow water flow, dissolved gas percolation and mud losses have resulted in extensive non-productive times and an inability to set casing at the desired depth. Rate of Penetration (ROP) was excessively limited due to cuttings build-up in the hole as the result of low annular velocity. The pressure increase in the wellbore due to the cuttings loading was sufficient to cause losses to the formation. A new managed Pressure Drilling (MPD) system, developed for drilling subsea wells, uses proven subsea mud pumps from the Riserless Mud Recovery (RMR) system to adjust fluid level inside the riser to maintain a constant Bottom Hole Pressure (BHP)/constant Equivalent Circulating Density (ECD). This compensates for changes in the wellbore pressure profile that may occur due to standard drilling practices and problems such as cuttings loading and annular frictional pressure loss. This technology, called EC-Drill, is also integrated with a reliable early kick/loss detection system which allows the driller to respond quickly before a situation escalates should influxes or fluid losses occur. Top-hole cement jobs also have been reportedly unsuccessful under such challenging conditions. Losing cement to the formation, plus the added problems of shallow gas and water influx, have been common elements in such failures. To slove the problem, a closed-loop circulation system was established to provide an excellent level of control over the return at the wellhead, so that wellbore pressure could fall inside the pressure window during placement of cement slurry. This cementing technique, called Managed Pressure Cemeneting (MPC), was successfully used in the Caspian Sea. This paper covers the principle of EC-Drill and MPC methods as well as field data for successful top-hole drilling and cementing operations.

The development of digital infrastructure in the oil and gas industry has led to the proliferation of advisory systems that provide recommendations in real time to mitigate a variety of risks. To deliver their full potential, these advisory systems need to coexist on a common platform across vendors and disciplines (e.g., hydraulic and pressure management, directional drilling, mechanical integrity of the drilling system, and vibration mitigation). Despite the rise of closed-loop automation, however, there is a lack for a scalable tool or platform that can orchestrate multiple digital advisors to coordinate sometimes-conflicting recommendations. Whilst industry players are well versed about determining recommendations, the conventional approach for this problem has been rule- and experience-based. That methodology is not scalable nor transferable. Through this paper we present a framework that structures the process of determining a unified recommendation in real time by integrating the advice from multiple independent digital advisors. The novelty of the approach resides in its ability to structure the process of determining safe and robust recommendations using a scalable and computationally inexpensive algorithm that can run on standard engineering computers at the rig site and virtual-remote-operations centers. INTRODUCTION Digital transformation has become an indispensable and significant part in drilling engineering. The digital transformation sweeping through the industry has led to the development of a variety of applications and algorithms to help drive drilling efficiencies, offset-well learning, and automated detection and interpretation of drilling events and dysfunctions. However, this global push has led to multiple challenges, discussed below. Different teams, divisions, entities, and companies have developed differing solutions that target similar or complementary problems, and the differing solutions may not be compatible or combinable. These solutions can rely on different methodologies (e.g., data-based, physics-based, or hybrid) and can have different technology readiness levels. Some solutions can have conflicting objectives that need to be harmonized to provide a consistent set of actions, such as advisory drilling parameters for automating operations. Typical examples are rate of penetration (ROP) that is typically to be maximized while not exceeding a technical threshold from a hole cleaning point of view, or drilling parameter targets and limits from directional, mechanical, or hydraulic objectives that can conflict as they seek to optimize different aspects of the drilling process. For instance, a vibration advisor (a case study is shown in (Greenwood (2016a,b))) can recommend increasing the rotations per minute (RPM) of the drill pipe and reducing the weight-on-bit (WOB) if a stick/slip vibration occurs. However, from a hole cleaning and pressure management standpoint it may not be advisable to increase the RPM because doing so might exceed the equivalent circulating density (ECD) limit. Similarly, to mitigate a bit bounce or whirl vibration, the advisor can recommend decreasing the RPM, whereas from a hole cleaning point of view the RPM can be recommended to be increased to achieve the target ROP under current average conditions. During such conflicting scenarios it can be difficult for a user or an automation platform to consistently determine the best recommendation from a drilling efficiency standpoint. There may not be a cohesive framework that encompasses the above challenges and the other factors that go into the well construction decision process. Also, there may not exist a common platform where independent advisory systems from different vendors and disciplines can coexist and an open composite advice produced in real time by integrating their recommendations.

The drilling fluid properties are critical for drilling parameters such as ECD (equivalent circulating density), surge and swab pressures and hole cleaning properties. To be able to optimize drilling parameters and improve drilling efficiency also the drilling fluid must be at optimum specifications. To have a more proactive fluid engineering where the drilling fluid at all times is as desired continuous measurements of drilling fluid properties are necessary. This paper will present the development of new equipment for offshore use for automatic viscosity and density measurements. The paper will discuss the technology in use, the implementation and qualification into harsh offshore environment as well as the resulting data obtained, transformed into digital data received at onshore operation centers. The measurements of drilling fluids properties and chemical compositions have been more or less unchanged for decades. The tests in use are manual and performed by the mud engineer normally four times a day. Based on these tests the fluid properties are engineered within given set points of selected parameters. This limited number of tests will often drive the fluid engineering into a reactive mode, where fluid properties must be adjusted due to drift in measured values. In this paper the experiences from introducing continuous measurements of drilling fluids density and rheology will be presented. Automatic measurements have been introduced by an operator on several offshore installations, both semi-submersible drilling rigs as well as jack-ups and fixed platforms. The use of the data in the fluid engineering process as well as in the drilling process will be discussed. Drilling Fluid parameters can now be measured automatically on the rig. The fluid properties can then be monitored from operation centers 24/7.This ensure improved quality of drilling fluid. When this is performed in combination with online hydraulic calculations improved drilling performance is obtained.

A central element to reduce drilling cost is to improve drilling operation by analyzing real-time data. Developing advanced real-time analysis tools is one way to improve the drilling operation. Two approaches which currently are used for optimizing the actual rotary drilling process are mechanical specific energy and inverted rate of penetration models. The mechanical specific energy method is defined as the work needed to destroy a given volume of the rock. It can act as a tool during the drilling operation to detect changes in drilling efficiency thus providing a method to optimize the drilling parameters to enhance instatanious rate of penetration. Rate of penetration models, on the other hand, can be used to calculate formation drillability considering the effects of drilling parameters, bits design and bit wear. Drilling optimization using rate of penetration models is done by changing the drilling parameters and/or bit design to find the optimum drilling scenario for an entire bit run. The mechanical specific energy log and the drillability ratio differ when mud weight is changed and when bits are worn. These two differences are due the fact that mechanical specific energy does not include bit wear as well as the effect of changing mud weight. By combining these methods and modifying the mechanical specific energy equations to incorporate these effects and the mechanical specific energy can be used as a real-time trending tool for bit wear estimations. In this analysis, wells from offshore Middle East and onshore North America are analyzed. The field results are very encouraging in that the bit wear for both roller cone and PDC bits can be predicted. The field validation of this new approach shows that the supplementary information on the bit wear status can in some cases benefit in the decision of when to pull the bit while it still is in the hole and thereby possibly improve overall economics of the drilling operation.