bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pre-Drilled Liner Standoff Estimation for Mud Removal using Stiff-String Model
Authors: Esteva Milton , Donis Erickson , Miller Richard 
Published: March 2022

Abstract
Open-hole gravel pack (OHGP) completions rely on having a clean wellbore and fluid environment at the time of construction to achieve optimum productivity. Drilling mud removal is imperative to achieve this purpose. In OHGP designs where a pre-drilled liner (PDL) is utilized across the open-hole interval, centralization of such a PDL assembly is key to accomplishing wellbore cleanliness during displacement of the drilling mud to completion brine. Unfortunately, due to the need to maximize the area open to flow within the PDL, the liner centralization strategy is limited. Furthermore, an inner string is needed for effective mud displacement from the bottom of the PDL. The presence of the inner string adds complexity to the mechanical interaction with the PDL, demanding higher centralization performance.
In this study, PDL standoff is estimated using a stiff-string model. This model overcomes the limitations of the soft-string model as it accounts for the mechanics of pre-drilled holes, the bow-spring centralizer, and loads imparted by the inner string.
Enabling Foam Application in PMCD Using a Hydraulics Model
Authors: Rao Sai Sashankh , Mollica Juan , Wu Qian , Samdani Ganesh Arunkumar , Gupta Vishwas Paul 
Published: March 2022

Abstract
Pressurized Mud Cap Drilling (PMCD) requires use of an annulus fluid that is slightly underbalanced to the reservoir; the use of foam is proposed for low bottomhole pressure applications. Such an application requires a foam hydraulics model to guide the planning and operations as pressure management is key for PMCD. This paper presents the development of a novel 1-D steady state wellbore scale foam hydraulics tool and its application to a PMCD operation. User inputs include non-Newtonian rheology, PVT, solubility, temperature profile, pipe RPM, and reservoir pressure. The primary operational parameters are the gas/liquid rates at the surface. The density and pressure profile of foam in the wellbore is calculated to guide the formulation development and determine optimum operational parameters. The challenge is to develop a foam that can at the same time balance reservoir pressure (density design), be pumped at the desired downhole rates (for influx management) at permissible surface pressures (viscosity design), and is stable under wellbore pressures and temperatures (formulation design). These opposing requirements make the design an iterative process. Sample hydraulics results are presented for an example well and a sensitivity analysis is performed to demonstrate the effect that various operational and well parameters have on the hydraulics of a foam system. Both the pumps-on and pumps-off scenarios are studied. Additionally, a CFD analysis is performed to study the effect of drill pipe rotation in an eccentric annulus on friction pressure drop. A non-monotonic trend is observed due to the competing effects between the shear-thinning behavior (reduces viscosity) and turbulence (increases effective viscosity). The hydraulic model is verified by comparing against analytical solutions, an industry standard drilling software, experimental data, and CFD simulations. The paper demonstrates the importance of a foam hydraulics tool for a PMCD application and how it factors into the overall design of a foam system. It is shown to be a critical part of the foam formulation development, selection of density, rheology, gas/liquid ratio, and target pump rates and expected pressures.
Best Practices to Improve Accurate Time Stamping of Data at the Well Site
Authors: Annaiyappa Pradeep , Macpherson John , Cayeux Eric 
Published: March 2022

Abstract
Due to the nature of the drilling process, there are several companies collecting data at the rig. Each company's data acquisition system applies its own time stamp to the data. Subsequent aggregation of data, for example in a data lake, relies on synchronized time stamps applied to the different data sources in order to collate the data. Unfortunately, synchronized time stamping is rarely true. This paper documents the different sources or errors in time stamping of data and provides some best practices to help mitigate some of these causes.
There are many reasons for unsynchronized time stamping of data from different sources. It can be as simple as clock synchronization at the rig: each data providing or producing company has an independent clock. It can also be due to where the time stamp is applied: for example, at the data source or on data reception. Additionally, it can be due to how the time stamp is applied: at the start of the interval, the mid-point, or the end.
Many of the protocols used at the well site have a high latency, mud pulse or electro-magnetic (EM) telemetry, or even WITS (Wellsite Information Transfer Standard), where the actual acquisition time may vary significantly from the time stamp. Perhaps finally, time stamping of derived data is always problematic given the unsynchronized nature of data sources.
Synchronization of clocks within the data acquisition network is extremely important. The resolution of time synchronization depends on purpose: motion control for example demands high-resolution time keeping. However, for the purposes of local time stamping, synchronization to a Network Time Server with a resolution of one millisecond is sufficient. The issue is on agreeing on the common source, and agreeing on passage of the time signal through firewalls.
Time stamping is a more involved matter, calling for agreement on standards and a degree of metadata transparency. The paper describes in some detail sender versus receiver time stamping, the downhole to surface time-stamp chain, and time stamping of derived data.
Systems automation and interoperability at the rig site – allowing plug and play access to equipment and applications – rely on an agreed upon network synchronization scheme. Indeed, designing applications that must handle uncertain time adds considerable complexity and cost, not to mention the impact on reliability. This paper presents an ordered approach to a quite resolvable problem.
Modelling the Economic Impact of Spacing Uncertainty in Unconventional Long Laterals Due to Common Survey Practices
Authors: Cheng Katherina , Cosca Nicolas , Jose Minsu , Willerth Marc 
Published: March 2022

Abstract
Finding an optimal lateral spacing is crucial to maximizing the return on investment for unconventional assets. The estimates regarding these lateral spacings were made for various plays; however, in a general sense, they assumed that the wellbores were precisely drilled and surveyed (Bharali et. al., 2014; Lalehrokh & Bouma, 2014). Wellbore positions have potentially large uncertainties and recent studies demonstrate that these uncertainties are even larger than previously assumed (Love, et. al, 2020).This study combines the previous work completed on spacing uncertainty with a reservoir simulation model to better quantify the losses caused by positional uncertainty, while exploring the sensitivity of said losses in relation to the changing lateral length, well spacing and survey accuracy allowing for future optimal field development.
A previous method of simulating reservoir losses due to survey uncertainty, proposed by Maus & DeVerse (2016) and the major basins reservoir simulation using empirically derived positional uncertainty models generated by analyzing survey data from thousands of wells by Love et. Al., (2020) provided the framework for this study. The estimations for typical production losses due to survey uncertainty were produced from simulations and compared to similar simulations using industry standard error models. In all cases, a baseline simulation was run, estimating production losses observed on historical wells alongside additional simulations to determine the sensitivity of losses on future wells against lateral length (5,000 - 15,000 ft), lateral spacing (220 - 880 ft) and employed survey management techniques. The effect of estimated losses and deviations from expectations using standard error models were explored, including an analysis of average production losses, extreme events (such as maximum modeled production loss and number of lateral crossings), and the impact of uncertainty reduction techniques commonly employed through survey management.
After performing simulations using empirically derived well paths and uncertainty models, it was found that simulations using standard error models may have greatly underestimated recovery losses due to survey uncertainty. The empirical error-model simulations suggest that realized losses for common drilling scenarios may be up to 5% or more of expected production, a much higher value than the previously estimated value of 0.5 - 2% using standard error models by Maus and DeVerse. Simulations suggest that these losses can be reduced up to 80% using survey management techniques to improve the accuracy in wellbore positioning.
Up to present times, there has not been a quantitative look at how real drilling and survey practices employed in unconventionals impact field economics. This work synthesizes prior efforts to estimate the true surveying uncertainty and links it to an ultimate asset value.
Design of Carbon Capture and Sequestration CCS Wells
Authors: Ceyhan Ismail , Pilisi Nicolas , Suryanarayana P. V. , Krishnamurthy Ravi M. 
Published: March 2022

Abstract
This paper discusses a methodology for the design of wells in carbon capture and sequestration (CCS) projects. In addition to carbon dioxide (CO2) injection wells, CCS wells include observation or monitoring wells, as well as utility wells, which are used to reduce pressure by removing formation water.
The paper first outlines the differences between CCS wells and conventional oil and gas wells. These differences include much longer regulatory lifetimes, increasing pressure over well lifetimes, inherently corrosive environment, intermittent operation and large variation of CO2 injection stream properties depending on its impurities. These differences require a different approach to well design for CCS projects. A well design philosophy, which has been developed to address these differences, is presented. The paper outlines the material selection guidelines and tubular load cases. The design philosophy, material guidelines and load cases are illustrated through several example well designs.
For CCS wells, the design should start with the completion size required to achieve the desired CO2 injection rate, and progress outwards. Dual containment is essential; the second barrier must not only be designed for the corrosive environment, but the second barrier and its associated equipment must be periodically inspected or tested. All CCS wells, including injection, monitoring and utility wells, must be designed for potential CO2 exposure. Highest loads may be imposed during transient or upset operations, and may originate from changing thermal conditions. Cement integrity is essential to prevent undetected migration of stored CO2 out of the storage zones. Finally, it is necessary to have pre-prepared contingency plans to detect, shut-in, kill, repair and/or P&A failed wells.
The differences between CCS wells and conventional oil and gas wells require a different approach to well design. If CCS wells were to be designed using conventional methods, the wells might fail to maintain their integrity, thus resulting in the failure to contain injected CO2 in the sequestration zone.
Updating the Dull Grading System
Authors: Alam Mahabub , Case Spencer , Hussain Junaid 
Published: March 2022

Abstract
The IADC standardized dull grading system was developed for both roller cone bits and fixed cutter bits in 1987 and last updated in 1992. In the meantime, fixed cutter bits have taken most of the market share from roller cone bits; drilling technologies, tools, and features changed significantly. The current IADC dull grading system is unable to capture new information and has issues with consistency, accuracy, and precision.
A detailed analysis has been conducted using historically collected dull grading data that are available in the Ulterra database to understand the usefulness of the items in each column of the IADC dull grading system. The study surveyed people in different disciplines including sales, engineering, manufacturing, and marketing within the company to develop a novel updated dull grading system to make it useful across the board. The per-formance of the dull grading system is measured in terms of consistency, accuracy, precision, and compatibility with existing drill bits. The study evaluated and updated the structure (the way 8 columns are being divided), scal-ing of the worn cutters, and the items of the columns of the dull grading system.
The historic data analysis results showed that some of the items in the current dull grading system are ob-solete or rarely used. The survey of the study is designed to assess the performance of the current system and compare it with the proposed system. The survey analysis results demonstrate that the proposed dull grading system is more user-friendly, consistent, accurate, and precise. The proposed dull grading system is developed focus-ing on fixed cutter bits as those hold over 90% of the market share. However, the grading system applies to roller cone bits and the hybrid of fixed and roller cone bits. A few worn fixed cutter bits are graded and shown as exam-ples using the proposed grading system. A novel updated dull grading system has been proposed, where the structure of the system, requested in-formation, and the method of data collection for a dull bit is updated. Considering the advancement of automation and digitization, digitizing the dull grading system would be the most useful goal. The proposed updated dull grading system would be a step towards digitization.
Digitalized Operation Procedures Provide Rig Automation System with Context to Manage Longer and Broader Sequences of Activities
Authors: Farmanbar Pourya , Berge Anne Siw , Revheim Olav , Chekushev Alexander , Schaefer Serafima 
Published: March 2022

Abstract
The exact definition of all types of activities in well construction, from spud to completion, is an area of great challenges for an automation system to function successfully in. In an operation plan, these activities can be categorized into three subgroups: standard and repetitive sub-activities, customized sub-activities, and manual sub-activities. A digitalized detailed operation procedure (DOP) provides the appropriate context by defining the machine-readable version of these activities.
Digitalizing a DOP is achieved by splitting it into individual parts, categorizing them into activities, checks, risks, lessons learned, best practices, and operational parameters and constraints. This paper focuses on manual sub-activities (e.g. close/open valves or nippling up) in which start and end time are acknowledged manually; pre-defined sub-activities (e.g. drilling and tripping) which are defined by repetitive tasks (e.g. drilling, lower string, lifting string and connections); and custom sub-activities (e.g. recording slack off and pick up weight or pressure tests) which can be customized for a tool, company, or operation with limited tasks (e.g. increase flowrate or reduce rotation).
Adopting this approach guarantees:An unbroken consistency between the planned, executed and reported phases of an operation as the digitalized DOP is directly connected to the automation system and the detailed log of executed activities are recorded.Enabling automation of longer sequences as the rig state transition between activities is managed seamlessly. This also applies when it is interrupted by manual operations like making up casing hangers.Quality check and improvement of the automatically performed activities by using real-time models. This is not limited to the normal repetitive sub-activities such as drilling or tripping. They can be used for every related custom sub-activity, e.g., hydraulic modelling after the opening of a circulation sub or torque and drag calculations after releasing a liner running tool.
Having a software library consisting of categorized, distinguishable manual and automatic activities lets the user describe with precision the operational tasks in a standardized digital format. With each automatic activity being readable and recognizable by the rig automation system, the system can execute longer and broader sequences of activities securely and cost-effectively, where the sequence is well defined.
Model Predictive Control for Automated Drilling Fluid Maintenance
Authors: Feng Ivan , Gul Sercan , Chen Dongmei , van Oort Eric 
Published: March 2022

Abstract
Drilling fluids have a profound influence on drilling performance and well cost, both directly and indirectly through mud-related non-productive time. Despite the evident importance of optimal fluid performance, fluid treatment decisions are often based on superficial calculations or estimates using past experience by the mud engineer. Manual mixing of drilling fluid additives also poses significant environmental, health, and safety (EHS) risks. To help improve upon these issues, this paper introduces a model predictive control (MPC) algorithm for automated drilling fluid maintenance.
MPC is an advanced process control method based on predictive modeling of the system. Using such modeling, an optimization problem is solved to find the optimal input to move the system to the desired reference state. A methodology is proposed here for developing and applying hybrid composition-based models for MPC using machine learning techniques and analytical equations. Advantages of the proposed method are discussed, such as the ability to take advantage of estimated future formation types and rates of penetration for improved prediction of future fluid properties and the ability to implement lag time correction for various chemical additives.
The feasibility of this method was tested experimentally. A compositional model was developed for a simple two-polymer fluid using experimentally collected data. The lag time for chemical addition was also incorporated. Extensive laboratory experiments were conducted in a flow loop with a fully automated mud measurement and maintenance system, including a helical pipe viscometer, Coriolis meter, chemical screw feeders, and peristaltic pumps. A MPC algorithm was developed and tested to control and adjust viscosity at multiple shear rates by controlling the rates of addition of the two polymers. Tests were performed at various conditions; it was shown that the algorithm was able to achieve the desired control objectives.
Automated mud maintenance based on MPC is a promising method that will lead to more consistent and reliable drilling fluid properties. It takes advantage of formation knowledge and prediction to resolve issues inherent with simple PID control. Automated mud maintenance is aimed at eliminating the human error inherent with treatment decisions and manual mixing, leading to reduced fluid over-treatment/under- treatment events and reduced fluid-related non-productive time. Stable and consistent fluid properties will also enable better hydraulics control with improved ECD management in the field.
South Platte: A Case Study for New Deepwater Drilling Fluids
Authors: Champeau Mathieu , Nguyen Chau , Mouloungui Moussavou Juste , Allias Benoit , Szakolczai Cyril , Kenga Yannick , Brunet Jean-Marc 
Published: March 2022

Abstract
Deepwater operators are now exploring new fields that require products and services to be at the forefront of technology. This is especially true in the Gulf of Mexico, where fields with pressure gradients higher than previous developments are particularly demanding. In the coming decade, the Gulf of Mexico will see the first development using equipment rated at 20,000 psi. In such fields, density requirements for drilling fluids regularly exceed 15 lbm/gal, and can surpass 16 lbm/gal. Despite being green fields, narrow drilling windows can be expected, which can prove challenging when optimizing rheology at such mud weights. The South Platte field operated by TotalEnergies faced this challenge after a long absence in the Gulf of Mexico.
This paper presents the design, planning, and field execution for drilling fluids of the South Platte deepwater exploratory well in the Gulf of Mexico. The operator drilling team was anticipating several challenges for what would be its deepest well ever drilled, such as, the need of high-density mud (above 16 lbm/gal), with potential side effects such as fluids stability over long static periods, and potential drilling window limitation equivalent circulating density (ECD margin).
The selected high-performance invert emulsion fluid (HPIEF) was designed to address these challenges. Facing one of the most active hurricane seasons on record, with 30 named storms, multiple well suspensions were necessary (6 well suspensions, 4 BOP disconnections). This eventually led to static periods greater than the 15-days stability at downhole conditions. Those periods were targeted at the design stage.
Drug Related Problems in Hospitalized Patients with Kidney Diseases and Clinical Pharmacists' Services—a Prospective Study in China
Authors: Zhang Su , Huang Ping , Ren Yan , Lin Bo , Shao Yanfei , Ye Xiaolan 
Published: March 2022

Abstract
BackgroundThe patients with kidney diseases are at high risk of Drug related problems (DRPs) because of the multi-morbidity associated polypharmacy and pharmacokinetic change. The study aimed to identify DRPs in hospitalized patients with kidney diseases and the effectiveness of clinical pharmacists’ service in China.MethodsThe patients, admitted to the Nephrology department of Zhejiang Provincial People’s Hospital between January to December 2020, were enrolled in this prospective study. Clinical pharmacists’ service consisted of medication reconciliation, identifying DRPs and providing suggestions. The DRPs were classified using pharmaceutical care net-work Europe (PCNE) DRPs classification system, as well as all data were statistical calculated via SPSS version 26.0.ResultsFrom 914 patients with renal disease in the study, 45.95% of them had at least one DRP. A total of 463 DRPs were identified, and 84.23% of DRPs were solved with participation of clinical pharmacists. Presence of co-morbidities(AOR = 1.187[1.059–1.329]), polypharmacy (AOR = 1.050[1.031–1.069]) and hospitalization days (AOR = 1.035[1.001–1.071]) were predictors of DRPs.ConclusionDRPs were common in the Nephropathy hospitalized patients. Co-morbidities, polypharmacy and extended length of stay could contribute to form DRPs. Clinical pharmacy service is necessary to the optimization of drug therapy in hospitalized patients with kidney diseases.