bluuebunny/crossref_metadata_2025 huggingface dataset:
Permeability Study of API Class G and B Cements Considering Seawater and WBM Contamination
Authors: Le-Minous Jean Christophe , Mutti Didier , Bouvet Alexandre , Unanue-Rodriguez Iker , Chang Andy , Massie Iain , Xiao Erin , Schnell Ernst
Published: March 2017

In preparation for decommissioning work in the Southern North Sea sector, the permeability of historically used cement systems was investigated to help determine their effectiveness as well barriers. Because the placement of cement typically involves some degree of contamination with other wellbore fluids, determining the influence of seawater and water-based drilling fluid (WBM) contamination on the permeability of the set cement was of particular interest.

This study investigates the historically used API Class G cement at 16 lbm/gal and Class B cement at 15.8 lbm/gal using contemporary material samples.

Cores were prepared using neat cement, cement contaminated with up to 50 vol% seawater, and cement contaminated with up to 50 vol% WBM. The permeability to nitrogen flow of the set cores was measured using a Hassler sleeve.

To further investigate the structural changes causing the higher permeability observed in the contaminated samples, the structure of the cores was imaged using X-ray computer tomography (CT) scans.

All Class B mixtures within the investigated contamination range, all Class G mixtures with seawater contamination, and Class G mixtures up to 30 vol% WBM contamination produced set cores after curing.

The neat Class G cores showed approximately twice the permeability of the Class B cement cores, with the contaminated slurries of both cement types showing much higher permeability—approximately one to two orders of magnitude greater.

Further analysis using the CT scans revealed irregularities in the structure density in the contaminated samples, which might explain the increased permeability; however, further work is necessary to fully understand the mechanism causing this change. Understanding the potential effects of contamination on permeability and the structure could be useful for gaining insight into barrier performance of the cement sheath in circumstances where contamination is suspected.
Enhanced Formation Integrity Test FIT Interpretation and Decision Making Through Real-Time Downhole Pressure Measurements
Authors: Jebutu S. O. , Silbernagel M. , Dugas B. C. , Lamborn R. , Akimov O.
Published: March 2017

Acquiring accurate downhole pressure data for casing shoe test interpretation and real-time decision making is critical to the delivery of a safe, efficient, and cost-effective well. With modern logging-while-drilling (LWD) technology, pressure profiles from a formation integrity test (FIT) or leak-off test (LOT) can now be measured during wellbore pressurization, stored in the memory of the downhole tool, and transmitted in a compressed 60-point pressure versus-time data format via mud-pulse telemetry when circulation is re-established. This data are decoded and decompressed at the surface to provide a detailed downhole flow-off pressure profile. If a higher-resolution data set is required, a "zoom" function using the same telemetry loop can be affected over a selected (smaller) time interval to provide another 60 (enhanced) pressure points. The ability to transmit these data sets real-time, without a special downlink, saves rig time and ensures quality data as well as test objectives are attained before terminating the test.

FIT's are routinely carried out to determine the fracture gradient around the casing shoe (shoe strength), or the maximum pressure the wellbore can withstand with regard to the casing setting depth. The pressure profile can also provide an indication of the quality of the cement bond around the casing shoe. While picking an inflection point from the pressure-versus-time plot seems straightforward, there are a number of factors that can distort the FIT results and lead to interpretation difficulties, particularly when differentiating between cement problems and formation effects. Additionally, the effect of drilling fluid properties can induce inaccuracies in the interpretation of surface-collected data, often resulting in a higher pressure than the correct value. With the advent of data compression and high-speed telemetry technology, downhole pressure profiles can now be acquired with improved resolution. This enhanced data set is essential for robust FIT/LOT interpretation, the accuracy of which is critical for avoiding costly drilling problems. A Gulf of Mexico deepwater case history will be analyzed to display effective ways in which this emerging technology has been successfully implemented. This approach in downhole pressure measurements during FIT/LOT can provide on-demand, high-precision data sets for enhanced interpretation and real-time decision making.
Integrated and Longest Directional Casing While Drilling Mitigates Hole Problems and Improves Drilling Performance While Saving Drilling Time
Authors: Radhakrishnan Venkataramanan , Gonzalo Hevia Garcia , Borge Diego Barrero , Pickup Duncan Ian , Anggraini Fauzia Dwi , Kongoun Chortip
Published: March 2017

Directional Casing While Drilling (DCwD) with Steerable Motor or a Rotary Steerable System is an emerging technology with proven results in Casing While Drilling applications. DCWD has been successfully applied in wells in Asia, North Sea and Middle East using rotary steerable systems & PDMs, proving up its operational reliability. The technology has been implemented in Asia Pacific region as well overcoming several challenges. The project was successfully implemented in 2 back to back wells in Gulf of Thailand & being the first of its kind.

Since the DCWD is first of its kind in Gulf of Thailand and to the operator, a proper planning and detailing the procedures along with risk assessment is the key to the success of the project. The procedure, in addition to directional capabilities requires that the well meet the demands of anti-collision concerns within the torque and hydraulic operating parameters of the formation. The quest ot overcome the problems faced by the customer led the operator to choose the DCWD technology to deliver step changes in drilling performance while meeting company's strict operational and safety directives.

The Integration of the directional drilling segment along with DCWD team along with the operator and the drilling contractor resulted in achieving the following➢Longest 9 5/8 DCwD run world wide➢Highest angle achieved with DCwD run in the field➢Saved 2 days of drilling time compared conventional drilling➢Increase in on bottom ROP compared to offset wells.
Successful Deep Water Drilling MPD, Early Kick Detection and Performing Managed Pressure Cementing With CML Controlled Mud Level System in GOM and North Sea
Authors: Elahifar Behzad
Published: March 2017

Control mud level (CML) technology is a method to manipulate the mud level in the riser in order to control bottom hole pressure (BHP) and Equivalent Circulating Density (ECD). It is also a Dual Gradient Drilling (DGD) technology, designed for drilling post-BOP sections. The system uses a subsea pump installed on a modified riser joint (MRJ) to control mud level in the riser's annular space.

CML eliminates the effect of ECD and enables drilling with a close-to-constant BHP. This may impact well design by allowing more optimal placement of casing points. By eliminating circulating friction, flow rate can be increased in the horizontal section and in unstable formations, to clean the wellbore from cuttings.

CML is a valuable tool while drilling into formations with a high probability of losses, or the layers with a high risk of influx. This paper will show that a CML system detected kicks earlier than the rig crew and geo-service company sensors both in GOM and the North Sea. In addition, how quickly was the kick detected and the driller informed will also be examined. With the CML system, the sensitivity for kick detection was greatly improved as the effect of rig motion on surface volumes was eliminated.

It is also explained how the CML system can help drilling in weak zones, and also drill deeper by adjusting the mud level in the riser by using a subsea pump module (SPM) which is connected to the riser to control BHP. The system is not a part of the well control equipment and the mud is still the primary well barrier.

Successful managed pressure cementing (MPC) method is also covered in this paper. The system was used to manage downhole pressure for cementing operations to mitigate losses and ensure good cement integrity. With MPC offering precise control over the pressure, it is possible to keep the wellbore pressure profile inside the drilling pressure window during the cementing operation.
A Novel Rheological Hierarchy Optimization Methodology with Artificial Intelligence and Inverse Technique Improves Spacer Design
Authors: Xie Liangjun , Chen Zhongming , Chaudhary Saleem , Alegria Adriana Estela
Published: March 2017

The quality of zonal isolation and well integrity are two main objectives for a successful cementing job. These objectives require proper placement of cement in the annular depth interval of interest. Cement placement, in turn, is dependent on effective drilling mud removal. A spacer fluid is designed to aid displacement of the drilling fluid and to minimize cement contamination. It takes into consideration not only wettability tests and compatibility results between spacer/mud and spacer/cement, but also rheological properties to improve friction pressure hierarchy. The rheological properties vary depending on flow rate, polymer concentration, spacer density and temperature. Trial-and-error lab tests and re-designs are needed to establish a spacer to meet those requirements. To optimize the costly process, and to expedite the job design, it is necessary to propose a smart rheological hierarchy optimization methodology that can predict the spacer rheologies and polymer concentrations by leveraging information from known data.

In this paper, a novel rheological hierarchy optimization methodology with artificial intelligence and inverse technique is introduced to improve spacer design. First, sufficient existing rheological property data (FANN readings) as a function of spacer density, temperature and polymer concentration are used to train the machine learning algorithm. Second, depending on the selected mud and cement, density of the spacer and the bottom-hole temperature, the required spacer properties are predicted by the trained machine learning algorithm for each polymer concentration. Third, given the wanted rheological properties, the best solution can be found by the inverse optimization algorithm with the least- square error in the range of polymer concentration.

The proposed methodology is applied to a new class of spacer system, which is a premium, water-based spacer, designed to effectively displace the drilling fluid in the annulus. Hundreds of rheological properties are recorded with various combinations of density, temperature and polymer concentration. The data are used in training the nonlinear machine learning algorithm. In real cement-job design, with the required FANN readings of the spacer and FANN readings of mud and cement, the algorithm finds an optimized solution. The FANN readings predicted by the machine learning algorithm are compared in the inverse search step. The calculated polymer concentration and FANN readings are confirmed by laboratory tests with minor variations.
MPD Applicaton on ERD Well Offshore Venezuela – Managing Bottom Hole Pressure within Narrow Window in a Faulted Limestone Formation with an Static Underbalanced Drilling Fluid
Authors: Martinez Ricardo , Scotto Maurizio , Mendez Gerardo , Santaniello Filippo , Reda Mohammed , Rojas Freddy , Bustos Felipe , Tang Jose , Rojas Jimmy , Borges Sergio , Richards Dylan
Published: March 2017

This paper describes the use of the Managed Pressure Drilling technology in the largest offshore gas field in Latin American and the first offshore gas field to be brought to production in Venezuela.

Managed Pressure Drilling technology with the assistance of Continues Circulation System was successfully implemented in the drilling of an extended horizontal section across a fractured and faulted limestone reservoir in an offshore gas well in the Venezuela Perla field.

This paper presents the planning, operation and challenges faced while drilling across the reservoir and while running the production liner, how the severe losses were managed keeping the bottom hole pressure within a narrow mud window and preventing gas influxes with the assistance of the Automated MPD system

Managed Pressure Drilling (MPD) is a technology where well control is maintained during the drilling operation by using a constant bottomhole pressure through the application of a surface back pressure (SBP) with the utilization of MPD chokes and a Rotating Control Device (RCD). The accurate measurements of flow in/out are essential to the MPD system to provide early indication of well losses or gains with the use of mass flow meter to measure flow rate and mud density (Coriolis meter). The closed fluid system provides high resolution of mud density, flow rates and pressure with the ability to direct measure formation pressure at key places and fracture gradients without detaining the drilling operation.

The Perla field is located in the CARDON-IV block in waters of the Golf de Venezuela, 50 km offshore Peninsula Paraguana. Perla consists of one production platform with a total gas production 500 MMscfd dedicated for local consumption.

The objective reservoir is the lower carbonate at a depth of approximately 9000ft SS. The thickness of the reservoir is approximately 700ft. The anticipated production from each well is in the order of 80 MMCFD to 135 MMCFD with an initial condensate yield of 25-30 BC/MMCF.

In previous wells, severe lost circulations were encountered while drilling the Lower Carbonate Reservoir which has a formation pressure of 9.8 ppg at the top. Several LCM pills and eventually cement squeezes were required to control these losses. In some cases, major losses were encountered, resulting in early termination of the section. Losses of this magnitude are due to a fractured carbonate and the crossing of several faults along the open hole.
Inducing Axial Vibrations in Unconventional Wells: New Insights through Comprehensive Modeling
Authors: Wilson J. K. , Noynaert S. F.
Published: March 2017

Axial Excitation Tools, or AETs, are known to help improve ROP in modern horizontal wells. These devices instigate an axial vibration in the drillstring, which then propagates along the length of the horizontal assembly. The improvement in ROP is thought to originate from a more effective WOB transfer due to this induced axial movement from the AET. However, the exact mechanics of how these tools affect the drillstring is not known due to a lack of adequate modeling. Additionally, little work has been done to examine the potential consequences of inducing an axial resonance within the drillstring while utilizing these types of tools. This study explores these questions through advanced dynamic modeling.

Using a newly-developed, validated, comprehensive drillstring model, the dynamic response of the drillstring, due to the axial excitation provided by an AET, is examined via a forced-frequency approach. The resulting sensitivity analysis illustrates the dependence of the system on the various operational and structural characteristics of the drillstring. Parameters examined include applied WOB, wellbore trajectory, design characteristics of the AET, and various boundary conditions. Nonlinear time- domain simulations are also conducted in order to quantify how AETs affect the axial force transfer to the bit.

It is shown that various operational parameters will have a noticeable impact on the dynamic response of the drillstring when inducing axial vibrations while drilling. This observation suggests the necessity to properly plan for the use of AETs in order to avoid unnecessary failures of downhole components and subsequent non-productive time (NPT). While the modeling itself is advanced, the outputs are designed to help visualize the response of the system in a "user-friendly" manner, reducing the learning curve and bridging the gap between the "tech-savvy" and non-technical personnel.

This study presents an efficient way of determining the potential of harmful vibrations when drilling with an Axial Excitation Tool. The modeling approach shown is comprehensive and provides new insights into the fundamental operation of these types of tools and how axial excitations help to improve drilling efficiencies. Results presented show that induced vibrations do not simply "reduce friction," as is so often claimed; instead, these tools generate a dynamic axial force, oscillating about the average value, which may help work past "tight-spots" along the well. In turn, this would give the impression of reduced friction along the wellbore based on hook load measurements.
CO2 Self-Healing and Resistant Cement Technology From Laboratory to the Field
Authors: Engelke B. , de Miranda C. R. , Daou F. , Petersen D. , Aponte S. A. , Oliveira F. , Ocando L. M. , Conceição A. C. , Guillot D.
Published: March 2017

In a joint effort, an oil and gas operator and a service company have undertaken research to help overcome well integrity and cementing fluids challenges in the presalt wells of Brazil where some fields present high levels of CO2 in reservoir fluids. Results are provided from the laboratory phase to cement placement evaluation.

The new approach is to provide a cementing system that is not only resistant to CO2 attack but also has a self-healing capability in the presence of fluids containing CO2. The validation of the CO2 selfhealing and resistant cement technology was initiated at laboratory level. Then, a yard test with real-time field parameters was performed, proving that the new slurry can be mixed and pumped using conventional cementing equipment. Finally, an onshore well in Brazil served as a test well for deploying and evaluating the new CO2 self-healing and resistant cement system in the field.

The technology consists of an engineered particle size distribution (EPSD) blend containing a reactive material that swells upon contact with CO2. This swelling allows the closure of microfissures and/or the reduction of the microannulus, which heals the cement sheath and reestablishes the integrity of the well. Then, a large-scale yard test was performed to evaluate real-time field parameters such as the fluidity and homogeneity of the dry blend and the mixability of the slurry using conventional cementing equipment. After the success of the yard test, the technology was deployed in Brazil. During the field test, 8 m3 [50 bbl] of 1,900 kg/m3 [15.8 lbm/gal] CO2 self-healing cement was pumped downhole and placed in the annular space between a 7-in. casing and a 8.5-in. open hole to promote casing support and zonal isolation in the production zone.

The CO2 self-healing and resistant cement overcomes the deficiencies of conventional Portland cement in carbon dioxide environments and presents an advantage over other available technologies designed to withstand CO2 attack by maintaining zonal isolation and long-term well integrity. Moreover, this technology can be applied in any field in the world where CO2 is regulated and/or entails risk for operators or the general public.
New Innovative Underreamer Technology Simultaneously Drilled and Reamed with Two Activated Reamers
Authors: Grymalyuk S. , Schimanski M.
Published: March 2017

This paper presents and discusses the results of the field application where a new integrated expandable under reamer technology was implemented in the North Sea. An operator faced issues with wellbore stability and equivalent circulating density (ECD) while drilling a 12¼-in. section in a challanging formation. Placing the reamer close to the bit removed the need for an additional rathole elimination run, avoiding the risks associated with it and saving rig time.

The on-command digital, expandable under reamer is fully integrated into the bottom hole assembly (BHA) and can be monitored and controlled from the surface. The under reamer tool has unlimited activation cycles that provide the capability of selective reaming. The flexible placement of multiple reamers in the BHA enables near-bit and main reaming applications, and a combination of both. When used for near-bit reaming service, the reamer can reduce the rat-hole length to 4 m. Significant time savings and safety improvements can be achieved by simultaneously operating the main and the near-bit reamer.

In one run, the entire section was simultaneously drilled and underreamed to TD. The first 3,491 ft (1064m) were drilled while simultaneously opening the hole to 13½-in. with the main underreamer. The remaining 233 ft (71m) were drilled and reamed with both the main and the near-bit reamers activated. The rathole length was reduced to 33 ft (10m) in the same drilling run, saving 3 days of rig time. The 10¾-in. liner was then run to the desired depth. Minimal vibrations were recorded in the interval where both reamers were activated and stick/slip was nominal. After the run, an inspection of the reamer blades showed good performance and little wear.

The paper will summarize and describe the results and features in detail, and demonstrate how they can help the operators to reduce operational risks and save cost.
From Laboratory High-Pressure, High-Temperature Technology to Field Success: A Case Study on New Anti-Balling Coating Development
Authors: Yu B. , Goodman A. , Hayes B. , Stevens J. , Vondenstein T. , Callais R. , Harvey J. , Honeycutt J. , McEvers J. , Lindsey J.
Published: March 2017

Bit balling and balling on other bottom hole assembly (BHA) components is a common concern when drilling shale with water-based mud (WBM) because it limits drilling efficiency or in extreme cases can stop drilling, causing costly non-productive time (NPT).

Among many strategies which have been created to mitigate the above balling problem, an effective approach is coating the tool surfaces with hydrophobic materials that are generally characterized by high water contact angle. This approach has been pursued by bit manufacturers with some success; however, poor coating durability is still a common concern. Additionally, previous applications are often guided by surface hydrophobicity evaluated at ambient conditions. Elevated temperatures and wellbore pressures can potentially cause the behavior to change and limit effectiveness. Therefore, evaluating the surface hydrophobicity under conditions that closely simulate downhole conditions becomes essential.

To address these challenges, this paper reports the recent success on a new anti-balling coating technology and the novel high-pressure, high-temperature (HPHT) laboratory tests used to develop it. The laboratory-level HPHT apparatus developed in this study is capable of measuring key parameters including the contact angle and interfacial tension at extreme conditions of up to 500 °F and 30,000 psi. It is also demonstrated how pressure and temperature have an impact on the surface hydrophobicity.

The newly developed coating technology combines good surface hydrophobicity at HPHT conditions with superior wear performance. The development results were later demonstrated in several shale applications (Marcellus Shale, West Virginia in 2014; East Cameron, Gulf of Mexico in 2015), where the coating technology was applied onto 8 ½" diamond bits that at one time drilled up to 10,000 ft in a single run without requiring a trip while still maintaining coating functionality.

This development work provides drilling operations with an effective solution to improve the performance in balling-prone shale applications. Additionally, the body of work demonstrates the importance of material testing in conditions matching real-world applications and how this approach leads to improved material selection for solving downhole problems.
Integrating Human Factors into Well Control
Authors: Odgaard Jacob , Morton Tim
Published: March 2017

Human Factors encompass elements which influence our behaviour. In a work environment they embrace many areas, for example; environmental and organisational, the design and functionality of equipment, process and procedures, individual characteristics of personnel, their skills and competencies.

It is generally acknowledged many of the world's worst oil field incidents have been attributable to Human Factors including well control events like the Montara and Macondo blow outs and many others. It is notable that some well control incidents initially appear straightforward but are frequently exacerbated by human error, increasing risk and costs, and in the worst cases resulting in blowouts.

The oil field has been a little late in realising the importance of Human Factors but there is now recognition they are essential in successfully resolving well control events. The inclusion of Human Factors in managing well control events was also a recommendation of the OGP 476 report in 2012.

The corporate well control manual was refreshed to include Human Factors in the management of well control incidents. This required mapping the well control process, assigning personnel specific roles, defining contingencies, etc. whilst acknowledging the effect Human Factors has on the personnel involved. The intention was not to create a rigid structure but to rather provide a framework to guide the front line in dealing with a well control event. New policies and procedures were subsequently developed and included in the update.

It is recognised this new philosophy will require an ongoing commitment impacting well control procedures, client liaison, bridging documents, the assessment and assurance of teams, well control training etc. It is further acknowledged this is just a first step and there will be continued development and refinement of the management tools as the system beds in.
The Floating Factory Concept: Engineering Efficiencies Up Front to Reduce Deepwater Well Delivery Cost
Authors: Hebert James
Published: March 2017

Deepwater drilling needs improved efficincy. Since well delivery cost is a major component of deepwater projects, a 20% reduction in well delivery cost may pull deepwater projects back over the economic threshold. However, sustainability requires looking beyond market cycle price consessions and focus on longer term technology and innovation to drive down the well duration and cost. Accordingly, the industry needs to apply engineered soultions to increase operational efficiency and safety as compared to existing 6th Gen drillship designs.

This paper introduces a next generation drillship design concept, featuring a factory-like approach to well construction, grounded with input from operators and third-party service providers. Capitalizing on Lean methodologies, the design combines improved safety with automation and robotics to reduce bottlenecks and minimize controllable flat time for the entire well life cycle with a reduction in well duration and cost by 15 to 30%.

The author examines the distinctive vessel layout including a large flat and un-obstructed work deck, a high variable load capacity of 27,500 short ton (ST), and increased personnel on board capacity to improve the off-line transition from the drilling to completion phases. In addition, the reorganized drill floor replaces the standard derrick and substructure with a Dual Multi-purpose Tower (DMPT), employing robotic pipe manipulators capable of handling 180-ft stands. To meet future well design requirements, the hoisting system is engineered for at least a 1,500 ST static hook load at the elevators. Further, independent mud and brine systems with 11,000-bbl and 17,000-bbl capacities, respectively, with off-line tank and suction line cleaning, improve well displacement safety and efficiency. Moreover, a unique power distribution network improves both thruster availability and also allows maintenance while operating efficiently in an open buss configuration, thereby stretching the dynamic positioning (DP) operating envelope.

The target of this efficiency and safety-centric initiative is to reduce the operator's well cost and allowing future optimization of 40,000-ft-plus well designs in 13,200-ft water depth.
Transformation of Mindset - Cost-Effective Collaborative Well Engineering & Operation Delivers Record Horizontal Appraisal Well in the Barents
Authors: Hollinger Gerald , Trauner Stephan , Dupuis Christophe , Wendt Anke Simone , Breivik Dag H. , Myrvoll Odd Helge
Published: March 2017

Through a tightly integrated collaboration between an operator and a service company, the world's northernmost horizontal well was successfully drilled and tested. Set in the Barents Sea at 73° latitude 350km from Hammerfest, this project de-risked a future commercial field development plan for the Wisting field, which holds some of the largest known oil reserves in the Barents Hoop Area.

All three major well objectives were achieved: (1) proving drillability by landing the horizontal well approximately 250m from the seabed (a record for subsea wells) and geosteering for 1400m across several fault blocks, (2) performing a well test within a long interval of reservoir exposure (over 460m) to prove the added productivity of horizontals, (3) acquiring appraisal information: reservoir data in new blocks, estimated oil / water contact (OWC), geomechanical properties, etc.

This well was outside the envelope achieved before, and such an extended reach drilling (ERD) operation required a customized well engineering approach at every step.

In addition, the hole design was adopted to cater for the drillstem test (DST) string. Different casing designs, string designs and operating parameters were screened in dedicated studies, looking at equivalent circulating density (ECD), torque and drag, hole cleaning, prior experience and contingencies.

A combined 3D subsurface, pressure and stress model was built, calibrated to drilling observations, core data and leak off tests and then used as input for subsequent studies (mud window, rock strength for drill ability).

The geometry required a constant 9°/30m dogleg from kickoff (no tangent section) to land at reservoir depth. Any interval where that performance was not achieved would have resulted in overshooting the reservoir (too deep).

An oil-based mud design was adopted for several reasons, and a dedicated lost circulation material (LCM) strategy established to manage potential losses in the reservoir matrix, in fractures or faults.

Important planning and operational considerations were given to safety and logistics, and no issues resulted in this remote and environmentally sensitive area.

The mud motor strategy selected after careful engineering simulations landed the well at the reservoir depth, before geosteering near-horizontally for the required 1400m. The partnership has gained invaluable information about the drill ability of such wells in Wisting.

Several fault blocks could be accessed with a long horizontal, giving a positive impact on the field economics.
Reliable Mud-Pulse Telemetry System for High-Resolution Real-Time Logs
Authors: Greten Alexander , Brahim Imed Ben , Emmerich Wojciech , Akimov Oleg
Published: March 2017

For drilling directional wells and exact reservoir navigation, a broad spectrum of measurement-while-drilling (MWD) and logging-while-drilling (LWD) measurements, as well as drilling optimization-related measurements, are available. The data they generate are used for accurate characterization of the formation while drilling and for steering within the reservoir. Additional data is needed for a safe drilling process, and for achieving a high rate of penetration (ROP) while drilling the reservoir. The oil and gas industry has developed many technologies that enable real-time transmission of this data from downhole to surface. For decades, mud-pulse telemetry (MPT) has been the most common transmission system for MWD and LWD data. Depending on the geology and the complexity of the well, a multitude of MWD and LWD measurements are required simultaneously on surface. The number of desired logs increases as applications become more challenging and performance is pushed to maximize penetration rates. The additional data required from new and existing measurement technologies pushes the envelope of reliable and fast transmission of data via MPT.

To achieve real-time data rates that can accommodate all measurements, deliver the required resolution, and simultaneously achieve the planned ROP, a highly sophisticated and flexible telemetry system is required. This paper describes an MPT system that delivers high data rates and high reliability. The system includes a robust mud pulser and an improved, self-adjusting surface system. To overcome decoding challenges, the system has flexible options like diverse signaling types, various modulation schemes, and adjustable signal frequencies.

With this system it is possible to drill wells that have a very high real-time data demand without limiting the ROP or reducing the amount of transmitted information. This MPT system helps achieve the desired data density in MWD and LWD logs, and in borehole images.

This paper shows how the system enables data transmission from some of the most complicated instrumented bottom hole assemblies (BHAs), how it improves real-time logs and images, and how it lifts ROP ceilings while simultaneously increasing reliability.
A Systems Approach to Well Control Barrier Management During Drilling Operations
Authors: Thorogood John L
Published: March 2017

Well barrier verification is having the confidence and being able to prove that "the folk on the rig will do the right thing and the equipment will function as intended when called upon to do so". This paper describes a method of achieving that aim by analyzing well control barrier systems in a logical and complete manner with regard to the technical, operational and organizational elements so that the results can be used as the basis for a straightforward means of barrier verification during operations.

BowTie diagrams, while a useful illustrative starting point, are limited in their ability to depict well control barriers as systems consisting of individual elements that interact with each other. Portraying them as systems enables the processes, people and equipment required for effective well control to be analyzed in a way that is both logical and complete. Further examination of the elements reveals the critical aspects that must be checked to verify barrier effectiveness. Operationalising the verification process is done by extending and formalizing established practices of wellsite supervisor oversight and cross-checking complemented with periodic inspections.

The analysis is resource intensive because each operational mode must be considered separately to ensure completeness. Once this work is done, general themes within critical aspects emerge that enable the verification tasks to be grouped into a set of logical activities that include: conversations with crew members to verify knowledge, criteria for drills to check on team capability and periodic inspections to ensure equipment integrity. Although difficult to achieve, the process must be carried out in a way that engages the crews in a sense of self-preservation to avoid becoming a box ticking exercise.
How Experience Transfer and Learning Can Lift Knowledge From Individuals to the Organizational Level
Authors: Mathisen Petter , Andersen Mats
Published: March 2017

During a field development, huge amounts of data are created and gathered. To what extent is the captured data and knowledge actually reused? Is human knowledge and operational information effectively utilized in future projects and can it be used more efficiently during the development phase or the lifetime of the field?

Since 2014-2015, The pilot client has been focussing on implementing a software tool for collecting operational data and engineering experience. By creating a common "knowledge database", the operator makes sure the individual learning in each project is saved and made accessible on a company level. Based on the results recorded on the field development, the pilot client has seen that by standardising the knowledge management process, it is possible to locate features for improvement of effectiveness by minimising human error and ensuring motivation for working with optimisation across the company.

Learning across large organisations has always been a great challenge. During a field development a huge amount of data is collected over a longer period. Data comes from several sources in different formats – service companies, rig owners, technology providers, and licence partners. During a field development project, it is natural that the engineering teams want rather to spend time on operational project management than looking for data.

Based on the experience from both AGR and the pilot client, offset analysis often means a large portion manual data processing and searching for experiences. Working like this means that human error is not locked out. In addition it is very time-consuming and often creating repeated efforts, leading to non efficient resource usage. In the planning and execution of operations, it is important to learn from past experiences to avoid making the same mistakes several times, and to learn from others' success. Valuable experiences exist in most of the organisations, but are unfortunately often difficult to access for the end user.

To address the human element around creating and capturing data, The pilot clienthas focused on standardising the process at the same time prioritising knowledge management and skills development within the field development team.

To execute the focus, The pilot client uses software technologies to create a cloud based database of well data and experiences in one place, enabling easy access to visual displays for the user. Experiences are captured through a standardised user interface.

The engineering time is now spent on analysing data, not looking for it or if found spending hours on processing it.

The software visualises trends and opens window for detecting potential challenges in the project and identify missing data and risk. Similar information can be shared between teams onshore and offshore and information flow enables to map potential for improvement in effectiveness.
New Generation 3D Simulator Predicts Realistic Mud Displacement in Highly Deviated and Horizontal Wells
Authors: Tardy P. M. , Flamant N. C. , Lac E. , Parry A. , Sutama C. Sri , Almagro S. P.
Published: March 2017

Effective mud removal is a prerequisite to attain the cement coverage necessary for good zonal isolation. Because of this, the oilfield industry has dedicated considerable attention to the topic of mud displacement over the past 60 years. The first 2D annular displacement simulator was introduced in the 1990s and it is now widely available. The results are satisfactory for simpler configurations. However, for deeper wells with complex trajectories such as highly deviated or horizontal wells, the models start to show their limits. This paper discusses the advancements in mud displacement simulation that overcome the limitations of the previous generation simulator and provide a more realistic simulation in highly deviated and horizontal wells.

A new generation simulator now provides high-fidelity results via a combination of: 1) a pipe displacement model, accounting for fluid contamination inside the pipe; 2) a high-resolution annular displacement model, accounting for the complex 3D annulus shape with full determination of axial and azimuthal flows; and 3) a stiff-string centralization model based on the finite-element method, predicting casing position in a 3D wellbore.

A primary cementing operation for a horizontal well was studied and an unprecedented congruence was witnessed between predicted fluids annular concentration maps and ultrasonic cement log. The simulator was also able to predict complex channeling patterns in the annulus. These results allow a better understanding of the cement placement technique and provide means to optimize the sequence of fluids to achieve effective mud displacement in the well.

Enabled by advancements in today’s computing capabilities, the new simulator is able to simulate both simple and highly complex scenarios more realistically. Finally, the new model allows better planning and decision making to achieve zonal isolation and well objectives.
A Proactive Safety Culture Leading to Reduced TRIR
Authors: Robert Seth , Fiffick William , King Kenneth , Guillory Robert
Published: March 2017

The following is a 5 year case study for a drilling services and manufacturing company describing an employee driven safety program. The results show the downward trend of the company TRIR from 2011 to 2015 and discusses the tools and techniques used to lower the rate year after year.

In 2011, a companywide initiative was launched that introduced safety teams for every team member of the organization. Through routine safety team meetings, improved communication, safety projects, and safety training the company began a journey of increased awareness and appreciation for individual safety commitments. Throughout the 5 year journey new tools were introduced, such as behavior based safety programs and increased visible management commitment with an end result of a reduced Total Recordable Incident Rate of 85%.

In 2011, there were 18 recordables resulting in a Total Recordable Incident Rate (TRIR) of a 1.3. Safety teams were introduced throughout the entire organization and new safety tools were implemented, such as behavior based safety and improved communication. In 2012, the TRIR was reduced to a .66. Different tools and trainings were introduced for front line supervisors and individuals. The safety culture continued to improve throughout the organization. A sense of excitement and awareness became visible. In 2013, the TRIR was lowered to a .45. New initiatives continued including annual safety themes and management led initiatives, such as Safety Week. In 2014, the TRIR was a .46. The mission to zero continued and leading measures evolved. Improved safety training was offered and an improved new hire orientation was implemented that included active participation from senior management. In 2015, the TRIR was a .20.

This case study covers all the changes and initiatives that were implemented over the 5 year journey, step by step, that led to the decrease in the TRIR over the last 5 years. This is an example of a proven model with lessons learned that is scalable and can be implemented in any organization looking to reduce their TRIR and improve their safety culture.
Predicting Rotor-Stator Fit in Positive Displacement Motors PDMs
Authors: Alvarez Alfredo A. , Boscan Jorge
Published: March 2017

One of the most challenging aspects of using positive displacement motors (PDMs) is understanding the influence of each variable on the motor functioning and failure modes. Rotor-stator fit is the most critical factor in achieving maximum service life and performance. The objective of this paper is to present a new method to predict the rotor-stator fit that accounts for all main downhole variables.

This new methodology will enable the selection of a rotor-stator combination that delivers a balance between performance, efficiency, and service life. Fit selection is complex and should be made based on physics models, testing data, field data, and experience. However, downhole temperature is commonly the only variable used to calculate thermal expansion of the elastomer and the resulting rotor-stator fit. Effects of environmental conditions and operating parameters are normally neglected. This paper presents a calculation method for predicting rotor-stator fit in PDMs that includes environmental conditions and operating parameters.

A mathematical model is proposed to account for additional expansion caused by internal heat buildup (hysteresis). Additionally, a time-sensitive equation is used to estimate elastomer volume changes resulting from the interaction between the fluid and the elastomer. In conjunction with the equations developed, collected rotor and stator wear data captures the effect of rotor coatings, drilling fluid, solids content, and elastomer mechanical properties. An additional equation is also utilized to estimate the change of elastomer volume caused by the system hydraulics (downhole pressure and flow rate). Final fit prediction is obtained by combining all these effects. Normalized fit ranges can then be correlated with expected performance and risk of failure. After testing and validation, results from the new method have proven to be accurate in applications with both low and high downhole circulating temperatures and for different elastomer types, drilling fluids, and varying operational conditions. A real case is presented.

Unlike any current temperature-based prediction method, this new model integrates the effects of the most important downhole variables to accurately predict the rotor-stator fit. As a result, uncertainty in operations decrease; risk of failure is drastically reduced; and the reliability, performance, and service life of positive displacement motors are improved.
Use of Quantitative Risk Analysis Methods to Determine the Expected Drilling Parameter Operating Window Prior to Operation Start: Example From Two Wells in the North Sea
Authors: Daireaux Benoît , Cayeux Eric , Haavardstein Stein , Stokland Leif Magne
Published: March 2017

While in a well-defined context, drilling operations can be optimized to a great extent, other more complex drilling operations, either due to challenging trajectories or taking place in more unpredictable geological setting, may incur undesirable delays due to unforeseen difficulties. For such challenging drilling operations, it is more and more common to perform pre-operation verifications in the form of "drill the well on the paper" or "drill the well in the simulator". Such methods may help the engineering team to discover some of the flaws of the operation plan but they fall short in providing quantitative risk assessments of the studied drilling operation plan.

A methodology based on uncertainty propagation throughout all the input parameters of the drilling program has been developed to quantitatively assess the inherent risks levels embedded in a drilling operation plan. Hundreds of simulations are performed automatically to estimate a safe drilling parameter operating window for every depth of the planned drilling operation. The analysis of the obtained window size allows to determine the risk levels and which of them are the most predominant. This allows to check if the plan is robust and to prepare for countermeasures in case difficulties should be encountered.

This quantitative risk analysis method has been applied to two challenging drilling operations performed in the North Sea.

When a case has been described, the analysis is performed automatically and does not require any human intervention. The analysis of the results may thereafter be used by the drilling team to focus on the most essential challenges ahead of the drilling operation during the "drill the well simulation" session.