bluuebunny/crossref_metadata_2025 huggingface dataset:
Implementation of Wired Drill Pipe Saved Multiple Days Per Well, by Addressing Performance Limiters, Increasing Drilling Efficiency
Authors: Teelken Reina , Jaring Colin , Craig Andrew , Allan Roy , Roberts Huw , Hatch Andy , Shepherd Nicol
Published: January 2016

This paper will discuss the implementation of the Wired Drill Pipe telemetry on two wells of the Babbage development project in the Central North Sea and will present the quantified efficiency gains achieved across various drilling operations.

Wired Drill Pipe (WDP) telemetry enables bi-directional, high speed data transmission to and from downhole tools at speeds up to 57,600 bps (Olberg et al. 2008). This enables real-time "recorded" quality MWD and LWD data to be transmitted instantaneously to surface, as well as near-instantaneous commands ("downlinks") to be sent to MWD, LWD and RSS tools while drilling.

The contribution of WDP telemetry to well placement and Geosteering on the Babbage development project has been published previously (Hatch, et al. 2011).

This paper however, will present the efficiency gains and corresponding time savings that WDP telemetry enabled through the instantaneous transmission of data up and down the drillstring. A detailed analysis of the two WDP wells drilled with WDP telemetry will show the quantified time savings when compared to three wells drilled with conventional mud pulse telemetry.

The analysis will compare the time spent on several activities including the transmission of downhole data to surface and vice-versa, the frequency of unplanned bit or BHA trips and on-bottom drilling time. The analysis will account for the differences in BHA designs, well paths and controlled drilling practices.

Compared to the Babbage wells, drilled with mud pulse telemetry, a reduction of multiple days per well can be inferred through the increased efficiency of these operations and activities.
Collapse Strength of Casing Subjected to Combined Load
Authors: Greenip J. F.
Published: January 2016

Triaxial evaluation of loads is used extensively for casing and tubing string design and analysis. The paper presents a method of determining the triaxially based collapse strength of casing and tubing subjected to simultaneous axial and internal pressure loads. The triaxially based collapse strength method was recently adopted by the American Petroleum Institute (API) and an addendum issued to API Technical Report 5C3 (TR 5C3). Casing and tubing subjected to combined loads have higher collapse strength than previous formulas predict.

The triaxially based formula presented incorporates internal pressure and axial load simultaneously into the calculation of casing and tubing collapse strength. The formula is compared to the previous First Edition TR 5C3 uniaxial method of accounting for internal pressure. The paper compares both the uniaxial method and the new triaxially based method with API combined load collapse test data, validating the triaxially based formula. Casing design examples contrast the uniaxial method with the triaxially based method, showing the higher collapse design factors calculated when using the more accurate triaxially based formula.
Innovative Ability to Change Drilling Responses of a PDC Bit at the Rigsite Using Interchangeable Depth-of-Cut Control Features
Authors: Kenneth Evans , Russell S. Craig
Published: January 2016

Bit designers use the well-established practice of placing depth-of-cut (DOC) control features at strategic heights from the cutter profile to selectively manage drill bit aggressiveness and to maximize drilling performance. But, until now, the elements used for depth-of-cut-control were a fixed part of the bit. An innovative new feature enables compact element replacement and/or adjustments at the rig site using a mechanical locking design. The driller can quickly adjust the bit responsiveness before each run, if wanted, to optimize performance factors such as rate of penetration and tool face control. This paper describes the benefits, ease of use, positive results and reliability of this new technology with examples from multiple applications for a variety of bit designs.

The final design was selected and validated based on a number of evaluation methods including concept screening tests, simulated laboratory drilling tests and field tests. The initial screening tests evaluated the ease of compact installation and removal for various concepts using a test block. Full bit testing using a full-scale, high-pressure, downhole drilling laboratory evaluated installation, integrity and aggressiveness response changes using compact height adjustments. Finally, multiple field tests on wells in North American applications of the Eagle Ford, Marcellus, and DJ basin formations provided data to refine the mechanical design and improve manufacturing processes to achieve a robust technology.

Field tests proved the new design to be highly reliable, with drilling performance that matched or exceeded the performance of bits with standard brazed compacts in the same fields. This new design provided the unique ability to rapidly optimize bit responses. This paper describes the technical lessons learned, guidelines for use and tools developed to maximize the benefit from this innovative new feature.

This new method enables compact element installation and removal within fifteen minutes on the rig site for the purpose of repair or aggressiveness modification. In contrast, traditional methods of DOC control include long lead times to alter bit design, manufacturing and delivery. Drillers can reap the immediate benefits of improved bit performance by changing bit design on the rig site using direct feedback of bit aggressiveness and steerability between runs without needing multiple bits on site. Ultimately, this new bit technology provides improved drilling performance and greater efficiency for the operator.
World Record Using the Steerable Drilling Liner Technology to Secure Previously Non Drillable Section in Unstable Shale
Authors: Bossis Vincent , Grindhaug Gaute , Eidem Morten , Fjorden Jan , Ringstad Jim Roger
Published: January 2016

Challenging environments such as unstable clay formation represent high operational risk when running tubular after drilling is completed. Use of Steerable Drilling Liner (SDL) system combines drilling and casing of the hole, thereby mitigating the risk of not being able to run the liner due to time dependent formation collapse.

This case study presents the difficulties encountered with a Semi-Submersible rig on the Åsgard / Midgard field in the North Sea during 7″ liner running operations in unstable clay formation using the conventional approach (drilling 8 ½″ section first and then running the 7″ liner), the planning of a SDL operation, and the execution of the SDL operation as well as results compared to similar operations.

The components of the SDL system will be reviewed and explained. Detailed planning is crucial for a successful SDL operation. The simulation work will be described with focus on ECD management and hole cleaning strategy. Torque and drag will also be covered. Actual drilling parameters will then be compared with the simulations.

Two attempts were made to complete the section using conventional technology. It was decided to plan and execute a sidetrack operation with the SDL system after numerous unsuccessful attempts to run the 7″ liner. Drilling operation with SDL was carried out as planned. No major drag was found over the whipstock despite the high local dogleg. Very smooth drilling operation with steady drilling parameters was experienced during the execution and the rate of penetration was comparable to drilling the section conventionally. ECD was slightly lower than simulated but around 2 points higher than with conventional drilling. Good hole cleaning was achieved despite a challenging well geometry and the liner was left in hole after drilling was completed. The liner hanger was then run and set before the cementing operation started.

The SDL system allowed drilling more than 1000m of the 8 ½″ section, making this operation a new world record and turning the well from an economic disaster to a complete success.

The SDL system is a relative new technology under continuous improvement. The primary application of this system is its use in unstable formation where it is anticipated problems for running the liner conventionally. Indeed, shocks and drilling energy transmitted to the formation is greatly reduced with this system, preventing time dependent phenomena such as hole collapse.
A New Steady Weight-on-Bit Tool Reduces Torque and RPM Variations and Enhances Drilling Efficiency and Bit/BHA Life
Authors: Jones Steve , Feddema Chad , Sugiura Junichi
Published: January 2016

Maintaining steady weight on bit (WOB) while drilling can be difficult at depth due to drill string flexibility, wellbore friction and downhole dynamics. Variable slack-off weights and drill string buckling results in un-steady WOB that generates string- and bit-induced stick-slip and torsional vibration.

Variable string rotation speed in revolutions per minute (RPM) and differential mud motor pressure causes changes in length of the drill string. These changes in length are directly acting on the drill bit and can result is a very chaotic drilling situation that is extracting energy from the drilling process.

This paper describes the operation and field-test results from a new tool designed to maintain steady WOB. The constant weight on bit tool was instrumented with sensors to gather critical information on inclination, sliding toolface, vibration, string rotating speed and erratic RPM events.

The data gathered is presented to show downhole drilling dynamics improvements with the steady WOB tool incorporated into the bottom-hole assembly (BHA).
Subsea Driving of Conductors: a Cost Effective and Successful Alternative to Pre-Drilling for Moho Nord TLP Development
Authors: Navez Guillaume , Delabrousse-Mayoux Géraud , Moysan Anne-Gaëlle
Published: January 2016

Reducing deepwater development costs involves thinking about alternatives to the most conventional techniques and increasing synergies among disciplines. For deepwater well conductors, replacing the conventional jetting installation method by subsea driving constitutes, in some applications, one such cost-effective alternative. On the Moho Nord Tension Leg Platform (TLP) development in Congo, all 27 conductors were installed in only a few days with an installation barge and using subsea hydraulic hammers, an operation that would have taken a few weeks and would have cost significantly more if jetting had taken place from a deepwater rig.

This paper presents, from the perspective of an operator's drilling entity, some of the experience gained from this project. First, the reasons and development concept specificities which led to preferring this installation method are introduced. Then, the main engineering steps are addressed in some detail, from the geotechnical studies and the driving predictions to the fatigue engineering of both the conductor pipe and the conductor housing, and then recommendations relative to their specifications are made. The challenges regarding the engineering and procurement planning are highlighted and briefly discussed. The selected driving methodology, from the handling of the conductors to their driving to final penetration, is also addressed. Finally, the operations are debriefed in a post-job review.

Whereas conductor or pile driving has been used extensively in other applications and/or industries (shallow water drilling, offshore construction, etc.), its use in deepwater drilling operations with subsea hydraulic hammers and wellhead systems is recent and the published knowledge is therefore scarce. This paper adds to the body of knowledge by providing offshore development project managers and engineers with first-hand information about this alternative to jetting conductors, its potential benefits, and key engineering and operational challenges to be considered to make it a success.
Next Generation Kick Detection during Connections: Influx Detection at Pumps Stop (IDAPS) Software
Authors: Tarr B. A. , Ladendorf D. W. , Sanchez D. , Milner G. M.
Published: January 2016

At least 25% of all influx events on deepwater wells occur while making connections but few deepwater rig contractors employ kick detection alarms to alert the driller during a connection (Brakel et al. 2015 and Fraser et al. 2014). Due to the transient flow characteristics associated with connections, kick detection during connections is the most challenging to automate effectively. The Influx Detection at Pumps Stop (IDAPS) software was developed to provide early warning of abnormal flow back conditions during connections. Available flow-in, flow-out, pit volume, bit depth and hole depth real-time data is used as input data. Particular attention was paid to achieving high probability of detection (PD) at low false alarm rates (FAR) to minimize nuisance alarms, and fast influx detection times to reduce kick volumes. The use of IDAPS to reliably detect a formation fluid influx has improved safety, operational efficiency, and driller situational awareness. IDAPS has been deployed in an operator's real-time operations center for monitoring critical offshore wells since 2014.

During IDAPS operation, pumps-off occurrences are automatically detected and saved as unique events. Machine learning algorithms are applied to recent pumps-off event flow-out and pit volume data patterns to adaptively calculate limits for "normal" events. The adaptive nature of these limits allows IDAPS processing to adjust to changes such as increasing hole depth. Each new pumps-off event is evaluated in real-time and statistically meaningful deviations from the recent "normal" limits generate corresponding possible influx notifications at one of four confidence levels (low, medium, high, and confirmed). Additionally, based on data pattern recognition algorithms, the software detects and notifies the user of circulation system data validity issues that could otherwise impair influx detection performance, e.g., malfunctioning flow sensor, unusual pit volume gains, etc. Overlay plots of current and historical flow and pit volume data have been shown to be valuable in significantly reducing the time required by the user to validate anomalous pumps-off event data automatically identified by IDAPS.

Based on an extensive validation process, using available historical real-time data, the demonstrated false alarm rate for IDAPS was 1 per 195 connections with a 100% influx detection rate, with an associated confirmed influx detection time as fast as 84 seconds after pumps stopped.
Optimization of Rate of Penetration in a Convoluted Drilling Framework using Ant Colony Optimization
Authors: Jiang Wanyi , Samuel Robello
Published: January 2016

This paper presents a combination of artificial neural networks (ANN) and ant colony optimization (ACO) used to determine optimal rate of penetration (ROP). The Bayesian regularization neural network (BR-NN) was trained and compared to the modified Warren model for ROP. The efficiency and effectiveness of ACO was evaluated for the optimization of ROP. There is no acceptable universal mathematical model that accurately describes ROP because of complex downhole conditions. Analytical models or real-time data analytics are usually used separately to estimate and predict ROP. Combining and using both methods simultaneously enables efficient ROP estimates and predictions. ANN can calculate ROP as output; inputs include depth, weight on bit (WOB or W), rotational speed (N), mud flow rate (Q), and gamma ray. ANN can potentially be used with real-time raw data without an explicit mathematical model for ROP. ACO is an algorithm that mimics ants determining the shortest path between their nest and food source. The ACO algorithm for the travelling salesperson problem (TSP) is modified to optimize ROPs. BR-NN with three hidden layers is selected. The trained BR-NN compares to benchmark data with a correlation coefficient > 0.99. ANN is considered suitable to calculate ROP (or ROP0 without the bit wear term) from drilling parameters, including W, N, Q, depth, and gamma ray.

Similar to a typical ACO algorithm for TSP, the pheromone update includes three terms: decay, recent ant activity, and elite path of shortest distance. In the probability function, the ROP reciprocal (i.e., drilling time) replaces the distance. For the test example, ANN-based ACO reproduces the global optimal ROPs, which are obtained by brute force for the test example. ROPs can be overestimated because bit wear is assumed constant for each depth. By separating the bit wear term from ROP, ACO provides an optimal overall drilling time as compared to actual drilling time. The paper presents field examples to predict and estimate optimal drilling parameters. The ROP estimate using the new model was performed using actual drilling parameters. The calculated ROP profile closely matched the actual data with an error rate of less than 5%. The paper proposes specific procedures to estimate drilling parameters and predict ROP and bit life. ANN was used to calculate ROP from input data with high accuracy. This is the first time an ACO algorithm is examined for ROP optimization, and ACO reproduces the optimal ROPs for the test example. This study combines ACO and ANN and shows their great potentials in optimizing real-time ROP based on real-time measurements.
Mitigating Vibration Induced Drillstring Failures Using Data Analytics: Workflow and Case Study
Authors: Mirani Ankit , Samuel Robello
Published: January 2016

Failures associated with drillstring vibration continue to occur, despite the use of risk quantification techniques based on vibration intensities and root mean square (RMS) accelerations. This paper introduces the concept of modified vibration stability plot as a practical tool to minimize and predict vibration. It integrates the modified vibration stability plot with a feature modeling data analysis tool to predict drillstring failures caused by torsional and lateral vibration.

The modified stability plot provides optimum operating parameters, including weight on bit (WOB), revolutions per minute (RPM), and rate of penetration (ROP), to minimize vibration. However, actual real-time drilling parameters are not always optimum. Consequently, the deviation of real-time parameters from the optimum values are used to calculate "deviation vectors" using statistical tools. These are then used to generate operating stability clusters to detect outliers in the drilling data that signify potential vibration events. Safe operating limits and operating times have been proposed by integrating the clustering technique with vibration risk index and cumulative vibration intensity plots to mitigate failures. The workflow has been applied to cases in which severe and moderate vibrations were encountered downhole and at the surface, respectively. Extensive simulations were performed to compare the data from downhole vibration sensors. The results show that the workflow closely predicts the occurrence of sustained vibrations before an actual downhole string failure event. Prolonged operations outside of the stability circle can cause failures, depending on the fatigue strength of the material. The occurrence of outliers outside of the stability clusters are calibrated with actual drillstring failures to correlate cumulative vibration intensity plots with the time duration of a vibration event. This calculation helps to define a vibration risk index that can trigger decisions to stop drilling or to change operating parameters before a failure occurs. The workflow also simultaneously predicts the dominant type of vibration in the system and in causing failures. The study concludes by providing guidelines to integrate the vibration stability chart with data analytics and explicates the significance of a statistics-based risk index to initiate real-time procedures to prevent drillstring integrity failure.

The workflow proposed and validated with case histories strives toward cost-effectiveness and increased productivity. This paper also implements data-driven techniques for risk quantification. The results and the method for determining a risk index and operational limits are robust, and can be applied as a starting point for other string configurations in similar downhole environments.
Advanced BHA-ROP Modeling Including Neural Network Analysis of Drilling Performance Data
Authors: Evangelatos Georgios I. , Payne Michael L.
Published: January 2016

Significant research on bottom-hole-assembly (BHA) vibrations in conjunction with continuous improvement in polycrystalline diamond cutter (PDC) bits using fluid mechanics has increased drilling efficiency and reduced related problems. Despite the analytical advances, most BHAs and bit – motor combinations are still heuristically chosen and most optimization efforts are by trial and error. The reason for this is the bit-rock interaction and the dynamics that the bit exerts on the BHA are stochastic processes, and most analyses use simplified assumptions for this complicated interaction. In this paper, numerical solutions for the differential equations describing the motion and dynamics of the BHA are provided including impact effects with the borehole while drilling near vertical wellbores. Secondly, the dynamics of this motion are coupled with a neural network model that is calibrated on previous bit runs. This approach renders significant improvements in predicting the performance of different bit-motor combinations and provides a reasonable estimation of ROP without having to actually run those combinations and re-calibrate the model. The main reasons why a strictly deterministic, numerical approach cannot be successful is that even though the BHA properties are well known and vibration characteristics can be estimated, the impact forces of those components with an imperfect bore hole with variable formation properties cannot be precisely calculated. In addition, the forces exciting the BHA – drillstring system through the bit are complex, multi-modal and semi-chaotic.

The neural network is hence used to identify and calibrate a model of the bit-rock interaction, essentially acting to partially de-couple BHA effects from how each bit achieves ROP. Several parameters affecting the drilling process are used as input and help uniquely identify the bit-rock interaction for a range of drilling parameters. This approach allows for a reasonable extrapolation of the bit’s behaviour on a different BHA and with different drilling parameters.
The Use of Wired Drillpipe Technology in a Complex Drilling Environment Increased Drilling Efficiency and Reduced Well Times
Authors: Schils Saskia , Teelken Reina , van Burkleo Brian , Rossa Ove Johnny , Edwards Nils
Published: January 2016

This paper presents and discusses the results of a case study where Wired Drillpipe (WDP) technology was implemented on the Martin Linge offshore field development project in the Norwegian sector of the North Sea.

Martin Linge’s resources consist of a shallow oil reservoir and several, deeper, structurally complex, high pressure gas and condensate reservoirs. The oil reservoirs are being developed with long horizontal wells and several deviated wells are drilled to unlock the gas and condensate reserves. The field was initially discovered in 1975 but proved too complex to develop at the time.

Over the years several exploration and appraisal wells were drilled within a narrow pressure window, with multiple BHA runs per section. The complex drilling environment posed many challenges including severe losses, influxes, unstable formations and excessive downhole shock and vibrations resulting in poor MWD/LWD signal.

WDP telemetry enables bi-directional, high speed data transmission to and from downhole tools at speeds up to 57,600 bps (Olberg et al. 2008). Conventional telemetry methods only provide very limited bandwidth (8-12 bps) for real-time data transmission and can suffer from signal reliability under adverse conditions, for example: no mud pulse data transmission to surface when pumps off or at flowrates below tool settings, decoding issues during high levels of downhole shock and vibrations and unfavorable mud conditions, such as gelled cold mud, gas, high viscosity pills, mud additives etc.

WDP technology was implemented on the Martin Linge field development from the start of the development. The technology introduction cost off-set against the quantifiable benefits for the project was initially calculated close to break-even. Furthermore, the high upside potential associated with the use of this technology should allow improved well placement and have a positive effect on the quality of the drains drilled.

This paper will summarize how the high speed telemetry provided by WDP enables wells to be drilled without the typical limitations imposed by conventional telemetry methods. The analysis will focus on two areas of efficiency and performance improvement. Firstly, the quantified data transmission time savings due to the real time high speed transfer of critical data between downhole and surface will be discussed in detail. Secondly, the network performance, drilling performance, application of new technology and technology investment cost will be discussed.
Stuck Pipe Prediction Using Automated Real-Time Modeling and Data Analysis
Authors: Salminen Kent , Cheatham Curtis , Smith Mark , Valiulin Khaydar
Published: January 2016

A real-time method is presented to predict impending stuck pipe with sufficient warning to prevent it. The new method uses automated analysis of real-time modeling coupled with real-time data analysis. It can be applied to all well types for any well operation including drilling, casing running, completion activities, and re-entries. The method uses leading indicators of stuck pipe that were identified using historical data sets of 36 stuck pipe incidents in the Eagle Ford, Utica, Permian, and Gulf of Mexico. Four case histories show the utility of the new method in four shale horizontal wells for both drilling and off-bottom operations.

The new method combines two types of analysis: (1) deviation of real-time data from real-time model predictions using hydraulics and torque and drag (T&D) software, and (2) trend analysis (i.e., rate of change) of real-time data. Parameters used are pump pressure, flow rate, torque, rotary speed, hookload and drag, and weight on bit along with static inputs such as BHA and drillstring configuration and directional surveys. Additional parameters such as downhole ECD are used when available and improve the results. But the method is designed to monitor all well types and provide a stuck-pipe-risk log even using only basic instrumentation. A novel algorithm predicts the probability of stuck pipe which is presented in a real-time log.

Results demonstrate there is no single leading indicator present in all stuck pipe incidents. Consequently, relying on a single specific pattern (such as increasing pump pressure at constant flow rate) leads to inability to predict stuck pipe in some cases. Our early detection method relies on multiple indicators to strengthen the likelihood of detecting an increase in stuck pipe while avoiding false alerts. Deviations of parameters from model predictions have been used with success in the past by experts but the new method provides contextual awareness and provides thresholds that automate the process. A key element is the use of filtering for rig activity. Rate of change calculations provide valuable insight into rapidly deteriorating wellbore conditions when deviation from model predictions does not respond quickly enough over a short depth or time interval. The detection method was tested on four historical wells in which four stuck pipe and two near-miss events occurred. Testing showed that an alert was generated, on average, 38 minutes before the event. There were no false alerts recorded in these wells.
A Paradigm Shift in Well Control Training and Assessment
Authors: Denkowski Mark R. , Kelly Brenda G. , Garvin Mike
Published: January 2016

Human factors experts agree that about 80 percent of incidents in the oil and gas industry are the result of human error. Proper training and assessment is critical to reducing these incidents. Therefore, the upstream sector has implemented a program that represents a paradigm shift in well control training and assessment worldwide. This program focuses on the safety-critical knowledge and skills required for specific rig-based positions.

Members of the Well Control Committee of the International Association of Drilling Contractors (IADC) came together post-Macondo to redesign the well control training and assessment standard. They agreed to the following foundational elements of the new standard: five "levels" of training; curricula that are focused on the safety-critical job responsibilities of rig personnel; a standardized, proctored online knowledge assessment; enhanced use of simulation for individual trainees; clarified and enhanced instructor qualifications; and the expectation that trainees will complete the training and renew their credentials at the level appropriate to their job position.

The new standard requires trainees to be more engaged in the learning process and to undergo individual skills assessments. The knowledge-assessment database identifies specific knowledge gaps, allows instructors to review and close the gaps with each trainee before the completion of training, provides metrics regarding the alignment between the course taken and the trainee's job position, and affords analysis of instructor performance. Trainees have reacted positively to the new format and content and to the blending of theoretical and practical knowledge in the standardized assessment. Several unexpected benefits have been realized through this collaboration: 1) Development and implementation of the new standard is raising awareness of operational inconsistencies not only from company to company, but also globally. 2) Industry stakeholders can come together to find and agree on solutions and to address industry, public, and regulatory concerns. This effort represents a new kind of commitment to safety, one in which we hold ourselves and others accountable for the benefit of all.

When experts representing the primary stakeholders (operators, contractors, and industry trainers) came together voluntarily to develop and agree on this new standard, they were acknowledging that safety is a part of the non-competitive space of the oil and gas industry. Perhaps more importantly, they were acknowledging the significance of the human element in effective well control.
Avoiding the Money Pit: The Industrialization of Delivering Complex Drilling Facilities
Authors: Reid David , Yost Tom , Russell Ian , Cheung T. O.
Published: January 2016

Highly engineered, custom-built offshore platform designs begin with a simple plan to succeed based on managing complexity and risk, yet ultimately, the majority fail to meet the delivery, budgetary, and performance expectations that were identified at the beginning of the project. A significant amount of the Oil & Gas industry's largest facility undertakings were also discovered to fail in one, if not all, of the areas of hitting production targets. Those that were considered successful often achieved these results alongside documented longer deliveries and higher budgets from the outset, and very few that were discovered had best in class performance matching the development of Mobile Offshore Drilling Units (MODUs). This paper looks at the underlying causes of this phenomena and identifies patterns of execution and best practices for succeeding in an inherently complex construction environment. Two projects stood out and the best practices have been researched and compared to a third construction project with similar attributes, which are all discussed in Part One of this paper.

In Part One, the first two projects had well-defined relationships and outcomes and the third project suffered due to attempts to eliminate costs and a dysfunctional relationship between the driller, shipyards, and operator. All three projects were ultimate successes for the oil company. Part Two of the paper we look at the impact of the emerging practice of standardized drilling facilities that eliminates cost and complexity. We discuss in Part Three current drivers in our contracting model, and then Part Four introduces lessons learned from the recent build out of the MODU fleet. In the end, we will highlight how we as an industry can take advantage of the crisis of cost management in a low oil price environment. The theme of industrialization of the construction process is developed from the first two projects and carried into the MODU fleet, which implies that better performance is achievable and the overall complexity and cost of drilling facilities on platform rigs can become a reality.
Comparative Study of Formation Damage due to Straining and Surface Deposition in Porous Media
Authors: Khan Hasan , Mirabolghasemi Maryam , Yang Hongtao , Prodanovic Maša , DiCarlo David , Balhoff Mathew , Gray Kenneth
Published: January 2016

The infiltration of fines into a reservoir during drilling or water reinjection and the accompanying production decline or loss of injectivity, are long-standing problems in the petroleum industry. Here, we propose a methodology that combines two different pore-scale models to better quantify formation damage. Further we validate the proposed model with core flood experiments.

We first perform an experimental study of suspension flow into sintered glass bead plugs and measure changes in porosity and permeability. Specifically, glass bead suspensions of known mono- and poly- disperse combinations of particle sizes, concentrations, and flowrates are flooded through the core plugs, while keeping the total invaded particle volume constant. The resulting changes in porosity and permeability are quantified using a CT scanner and pressure transducers, respectively.

We then establish two different numerical models (each focusing on a different mechanism/length scale) to predict permeability reduction. The first model takes a pore-scale approach that models straining of larger particles through the pore structures extracted from X-ray tomographic images of rock and grain pack samples from first principles.

The detailed pore structure output from the first model is used as an input in the second model, which is a network model. This pore network model simulates permeability impairment caused by both large and small particles deposition in porous media. Forces exerted on small particles include hydraulic drag, gravity, buoyancy, electric double layer, and Van der Waals. Particle trajectories in a converging- diverging pore throat are calculated dynamically. We incorporate surface roughness and particle-surface interaction to determine particle detachment and attachment. Pore throat structure and hydraulic conductivities are updated dynamically to account for the effect of previously deposited particles. We finally compared the experimental results to simulation predictions and found that the combined pore- scale model is capable of predicting the porosity of the invaded core only in the deeper regions of the core.
Field Application Study of Zinc Based, Low Debris Perforating Charges
Authors: Zuklic Stephen , Myers Bill , Satti Rajani
Published: January 2016

All perforating operations cause debris, which can lead to wellbore restrictions, choked downhole hardware, plugged perforations, formation damage and operational problems throughout the installation of the completion. As a result, the industry has taken significant efforts to develop low-debris perforating systems. Low debris perforating techniques are important in maintaining a clean and productive perforation tunnel, as well as helping to reduce the risk of operational issues associated with debris during subsequent downhole tool operations. This risk minimization becomes even more important in complex completions with long zones at high shot densities (as often seen in sand control completions), in stacked completions where perforating on top of packers is required, and in horizontal completions, where debris can't fall into a sump area.

One of the common methods for reducing the effect of perforating debris has been the use of zinc cased perforating charges. However, any low-debris system must also still create the optimum perforation in terms both of tunnel dimensions (maximum depth and diameter) and tunnel clean-up (minimum debris / reduced perm zone). Further, to maintain the connectivity of the perforation, consideration must be given to how the debris is handled after the perforating event and to potential interactions among the perforating debris and the wellbore and reservoir fluids. Extensive lab studies have examined all the effects of zinc perforating charges in these areas, but it is also critical to properly apply this to field scale applications through procedural examination.

This study seeks to examine effects of perforating debris on field mechanical operations comparing different types of perforating debris. A comparison versus conventional steel-cased charges is also presented in terms of charge performance and dynamic clean-up effects of low-debris zinc charges. Further, an examination of chemical interactions of these low-debris systems in the field will be presented, and most critically, a comparative evaluation of procedural decisions and methods will be presented to show an optimum application of lab learnings to field scale applications.

This paper also presents several case histories of wells that have been successfully completed using low debris perforating gun systems with zinc cased charges. Critical aspects of minimizing and managing debris, well productivity and other operational successes will be presented as part of the case histories.
Field Application of an Innovative, Minimally Damaging Low-ECD Invert Emulsion Fluid for Drilling and Completion of HP/HT Wells: Update on Fluid Performance
Authors: Strand Morten Holger , Lunde Odd Halvard , McMillan D. Nelson , Clinch Duncan , Wroblewski Tomasz , Fleming Niall , Hireche Sammy , Vatne Åsgeir , Karunakaran Mary , Ibragimova Zalpato
Published: January 2016

Previous publication SPE-174176-MS discussed the development of a novel high-pressure/high-temperature (HP/HT) organophilic clay-free (OCF) invert emulsion fluid (IEF) for first use as a combined reservoir drilling fluid (RDF) and screen running fluid (SRF) for stand-alone screen (SAS) completions. The current paper details the continued application of this innovative fluid in a total of five wells (four SAS, and one cased and perforated), and expands on the knowledge of fluid performance in the field.

Drilling performance, screen running performance, and productivity outcome were compared as previously determined on the first well. Additional finger printing was carried out to further understand the behavior of the 1.96-specific gravity (sg) OCF IEF: Downhole pressure measurements were compared to real-time hydraulic simulations, and were used to determine the actual pressure to break gels.

When drilling, all of the wells’ reservoir sections reached total depth (TD) without issue and with improved drilling performance. Rheology profiles were low throughout, delivering low equivalent circulating density (ECD) values. There were no incidents of barite sag during trips, and there was good gel development when static with gel strengths in excess of 15 pounds per hundred foot squared (lb/100 ft2, 10 min). Despite this, low flow rate testing (60 L/min) demonstrated very low downhole pressure to break gels (5 bar / 72 psi). At TD, fluid conditioning for screen running was achieved quickly (<12 hours). The 610 micron (µm) SAS were run to TD without issue. Since put on production, all the SAS wells completed with OCF IEF are producing with no apparent negative impact of the OCF IEF.

The OCF IEF has now been used successfully to drill five reservoir sections on an HP/HT field, delivering a low ECD performance without barite sag. The SAS completion wells were drilled and completed in the same fluid with an enhanced drilling performance and acceptable productivity outcome. The continued use of this single combination fluid has removed the need for a fluid displacement to a costly dedicated heavy brine SRF, resulting in substantial time and cost savings to the operation.
Field Implementation of an Oil Based Carrier Fluid Improves Gravel Pack Efficiency
Authors: Strachan C. , Kaarigstad H. , Arnestad E. , Nesse O. Bernt , Gadiyar B. R. , Phatak A. , Green S. , Sandberg G. M. , Sedberg S.
Published: January 2016

Open hole gravel packing of reservoir sections drilled with oil based fluid is traditionally performed with an aqueous carrier fluid. This typically involves displacing oil based fluid to aqueous fluid once the gravel pack screen is in place. In reservoirs with swelling or unstable shale this approach reduces the risk associated with open hole exposure to aqueous fluid over time. However experience has shown that instability can still occur resulting in an incomplete, or even an aborted gravel pack. In addition, mixing of incompatible oil and water based fluids downhole has the potential to generate very viscous emulsions that negatively impact gravel pack efficiency and well productivity. The objective of the new technology was to maintain borehole stability, eliminate fluid incompatibility and enable a complete gravel pack.

An oil based carrier fluid has been developed and qualified using laboratory and yard scale testing. The fluid is a solids free invert emulsion that exhibits near Newtonian rheological behavior; thereby promoting settling of proppant during gravel packing. The density of the fluid is controlled by adjusting the volume fraction and density of the brine phase. The fluid has been qualified up to a density of 1.25 SG with further potential to achieve a density of 1.63 SG.

The oil based carrier fluid has been introduced on a mature field, with a long history of gravel pack completions. Progressive reservoir depletion has created operational challenges, resulting in inconsistent gravel pack performance. Consequently, several procedural changes have been implemented over time. Reservoir inclination is typically up to 50°, open hole length up to 200 meters, and bottom hole static temperature around 90°C. Gravel packs were most recently performed with a 1.10 SG aqueous carrier fluid.

The new carrier fluid has exhibited stable properties during implementation on multiple well completions. Gravel pack efficiencies have been consistently good, at 100% or higher. As a result, well productivity expectations have consistently been achieved or exceeded. The operational time for installing the lower completion compares well with the traditional approach with aqueous fluid.

The implementation of oil based gravel packs in multiple wells, allows a comparison with brine based gravel packs in the same field. It is therefore considered to be an industry first.
High-Pressure Filtration Unit for Completion and Workover Fluids
Authors: Alrashdan Mahir D. , Defrees Andrew , Carbrey Lee
Published: January 2016

Debris management is essential to successful completion operations. A High-Pressure Debris Unit (HPDU) was developed to maintain a solids-free environment during completion and workover operations. The HPDU protects downhole tools and equipment by keeping completion fluid and workover fluids free of damaging debris. The HPDU is utilized after the remaining drilling fluid is displaced by completion fluid. The system has repeatedly demonstrated its value in preventing foreign objects from entering the wellbore. Debris is removed from pits, valves, pumps and other equipment before those solids can enter the wellbore.

The HPDU system is installed at the standpipe and comprises a skid-mounted panel of eight high-pressure filter units which may be operated at pressures up to 10,000 psi and circulation rates up to 34 BPM with a future upgrade to 15,000 psi. The operational parameters enable the unit to operate at high flow rates and the unit is suitable for deepwater applications. Eight filter units, aligned four on each side, house 8- or 12-gauge gravel-pack screens. The system is operated one side at a time to enable uninterrupted continuous filtration downstream of the rig triplex pumps in the event one side plugs. The HPDU can also be easily by-passed to enable for sand control pumping operations and viscous sweeps.

This system was deployed and used in 60 different wells, primarily in the Gulf of Mexico. It has been in use since 2011 and the precursor system has been used since 2000 in 95 wells. The system can remove debris before entering the wellbore and captures damaging debris contained or dislodged in the tanks or transfer lines. In a case study, 5,286 bbls were pumped through one side and 4,329 bbls through the other side to capture 10.8 lbs and 9.2 lbs, respectively. The captured debris comprised predominantly iron-rich scale fragments, barite, calcite, sunflower seed hulls and bulk material.

This paper presents the advantages of the HPDU in optimizing completion and workover operations by reducing downtime and preventing damaging material from affecting the downhole equipment operation. The HPDU acts as the final line of defense in downhole debris management, protecting downhole tools and equipment by keeping completion fluid free of damaging debris. Working in conjunction with diatomaceous earth (DE) and cartridge filtration, the system removes solids before they can enter the wellbore. Case histories of the deployment of the HPDU and the recovered debris are presented.