bluuebunny/crossref_metadata_2025 huggingface dataset:
Increasing Long-Term Fatigue Performance of an API Box Boreback Using an Enhanced Non-Truncated Thread Design and Revised Machining Methodology
Authors: Hauze Gregory R. , Gokhale Samit
Published: January 2016

Stress Relief Features (SRFs) are commonly added to Rotary-Shouldered Connections (RSCs) to increase the fatigue performance of the connection. An SRF aims to lower the critical stress at the last engaged thread and improve fatigue performance. The most common SRF prescribed by the American Petroleum Institute (API) for API box connections is the API Box Boreback.

The API Box Boreback SRF is added to an API RSC by boring out both the box threads and ID to a specified cylinder diameter and depth from the box shoulder. The API boreback is then finished by profile turning a tapered transition of specified angles and lengths which connects the back of the boreback cylinder to the ID of the component. The traditional method of boring the cylinder diameter due to the tapered threads of API connections causes a removal of the thread crests at the back of the box. These truncations of the last engaged threads reduce the contact area of the thread flanks available to support the load. The repercussions of this include an increase in stress concentration, reducing the fatigue life, and an escalation in susceptibility to thread wear, which inevitably amplifies the effect of the thread truncation, further reducing the fatigue life and cancelling out the benefits of the SRF. Details of this phenomenon can be found in IADC/SPE 128931 (Gerdes & Lee, 2010).

Despite its popularity, the API Box Boreback SRF can lose its effectiveness as the thread truncation at the back of the box can accelerate crack initiation and cause premature failures. To remedy this, an experimental study was undertaken to develop a machining method to cut a boreback with an enhanced non-truncated geometry on API box connections. The modified boreback geometry and machining methodology were perfected over multiple iterations, prototyped with a Computer Numerical Controlled (CNC) lathe using various routines and tooling selections. The dimensions were verified to conform to the requirements outlined in API Specification 7-2 and the machining process was validated on multiple API box connection types.

This paper presents details of a modified design and a universal machining methodology developed to cut an API compliant Box Boreback which retains full-height threads at the back of the box, avoiding thread truncation, and preserving the increased fatigue performance a Box Boreback provides well into the life of the connection. The method meets all dimensional requirements outlined in API Specification 7-2, ensuring proper make-up. The machining process can be performed on either a CNC or manual lathe. The enhanced boreback design provides a drastic improvement in fatigue performance over the standard API Box Boreback design, while maintaining all other structural and dimensional design aspects, and without altering the make-up torque or Bending Strength Ratio of the connection.
New Instrument Performance Models for Combined Wellbore Surveys Facilitate Optimal Use of Survey Information
Authors: Ledroz Adrián , Bang Jon , Weston John
Published: January 2016

In order to determine confidently the path of a wellbore, established practice involves the collection of multiple survey data using the various methods that are available to the industry, such as measurement while drilling methods, using either magnetic or gyroscopic measurements, or surveys taken after a section of the wellbore has been completed, normally using gyro tools. The survey deemed to be of the highest precision, based on published survey system error models, is commonly selected to be the "definitive survey" for that section of the well and all other data is discarded. However, by combining multiple data sets through the use of survey averaging techniques, it is possible to obtain a more accurate estimate of wellbore position.

Having generated a "combined survey" by such an averaging method, i.e. a survey generated by combining two or more surveys that may be of the same or different type, it is then required to quantify the accuracy of that survey. This may be expressed in the usual manner as a sequence of error ellipsoids at intervals along the path of the well. At present, however, this can only be done by rigorous calculations analogous to the survey averaging itself. This is a complex analysis, which is one important reason why survey averaging has not been generally implemented and adopted as a standard analysis practice.

Error models for individual survey tools are usually specified in terms of Instrument Performance Model (IPM) files in accordance with methods and procedures derived through the work of the SPE Well Positioning Technical Section. The IPM files, along with wellbore trajectory data, form the inputs to standard error model software packages through which survey uncertainty is calculated to a specified level of confidence. This paper demonstrates how new IPM files can be generated for combined surveys. The error analysis resulting from the new IPM file is shown to be consistent with the results obtained through the rigorous mathematical analysis of the individual surveys.

The introduction of new IPM files offers an easy and efficient method for operators to utilize all available survey information in a consistent manner. This may help to optimize the surveying program, with implications for both positional uncertainty assessment and safety aspects. Furthermore, the improvement in the positional data as well as the reduced uncertainty that can be achieved by combining surveys is a great advantage when considering small targets, very long extended reach wells, and highly congested fields in general, as it might turn unfeasible projects into achievable ones.
Quantifying Asphaltene Content from Downhole Optical Spectral Data during Sampling While-Drilling Operations
Authors: Indo K. , Pop J. J. , Hsu K. , Qi J. , Agarwal V. , Garcia Mayans A. , Ossia S. , Haq S. A. , Varughese J.
Published: January 2016

Over the last two decades downhole fluid analysis (DFA) using visible and near-infrared spectrometry has proven to be one of the most effective means for obtaining accurate and detailed reservoir fluid property information during formation tester operations. In a previous publication (SPE 166464) a methodology was introduced for estimating fluid properties, such as fluid type, hydrocarbon composition (C1, C2, C3, C4, C5, and C6+), carbon dioxide content, and gas/oil ratio (GOR), from downhole optical spectrometer data acquired during sampling operations. We have extended the methodology introduced in the previous publication to the real-time estimation of asphaltene content of black oils.

The equation derived for quantifying the asphaltene content of crude oils uses optical densities (OD), the absorption coefficients of asphaltene and resin, stock tank oil (STO) density, resin content and formation volume factor (FVF). In the process of deriving the asphaltene content a new method was devised for estimating FVF from optical data. The unknown parameters in the equation and the uncertainty in the estimate of asphaltene content are calibrated against a database that contains asphaltene content data of various crude oils and the corresponding optical spectra. Using the derived equation, a maximum likelihood estimate of asphaltene content of crude oil and its associated uncertainty can be obtained.

The accuracy of the method for estimating FVF and asphaltene contentwas verified and validated using laboratory crude oil data. The method was also applied to downhole optical spectral data acquired during a sampling-while-drilling (SWD) operation. It was found that the estimated asphaltene content and FVF obtained from the measured downhole spectral data showed very good agreement with the results of laboratory pressure/volume/temperature (PVT) analysis performed on captured fluid samples.
Cement Placement with Tubing Left in Hole during Plug and Abandonment Operations
Authors: Aas Bjarne , Sørbø Jostein , Stokka Sigmund , Saasen Arild , Statoil Rune Godøy , Lunde Øyvind , Phillips Conoco , Vrålstad Torbjørn
Published: January 2016

Well abandonment operations can be very time-consuming and costly, and thousands of wells need to be permanently plugged and abandoned offshore Norway during the upcoming years. One possible way to reduce costs during P&A operations is to leave most of the production tubing in the well, as this would save significant rig time. A major concern with such an approach is, however, whether the cement will properly displace the original fluid, due to lack of tubing centralization and possible unfavorable flow dynamics in the annulus. In this paper, we demonstrate by full-scale experimental tests that it is possible to obtain good cement placement when the tubing is left in the hole, with and without control lines.

Full-scale tests have been performed with both conventional and expandable cement to determine the sealing ability of annulus cement when tubing is left in hole. The quality of the cement placement was evaluated by pressure tests with water; where leakage rates and pressure drops over the test sections were recorded, and by visual inspection after cutting the test assemblies at different places. It is seen from the experiments that cement is well placed in the annulus when tubing is left in hole, but some microannuli are detected.
Industry Initiative – Testing, Certification & Training of Drilling Supervisors to Improve Safety and Performance
Authors: McAteer Peter , Dimitriadis Klisthenis , Taylor Charlie , Kelly Chris , Selbie Gary , Warren Andrew , Whatson Neal , Warner Randy , Holloway Pam
Published: January 2016

This paper outlines a new industry initiative and system supported by a group of Operators to reduce NPT and enhance safety performance.

It addresses competency of Well-Site Supervisors with a group of Operators aspiring to create industry-wide certification. Its paradigm is Well Control Certification which it will complement, addressing all other areas within both drilling and completions.

Competence and experience validation requires a systematic, reliable and repeatable approach. The paper will outline the challenges and response of an Operator group to Well-Site Supervisor Testing, Certification and Training.

The Vision is to set the hallmark for quality Well-Site Supervisors globally by providing regularly updated certification.

The objective is to: Prevent repetitive mistakes that cost the industry $billions each yearDifferentiate reliable people and support those that need assistanceMeasure reactions to simulations of events that occurred by presenting them as they unfold (to avoid hindsight engineering)Provide tools to improve and measure the individual's developmentShare the resource of quality graded Well-Site SupervisorsIncorporate ‘Human Factors’ to test interaction

The downturn represents a unique opportunity to set a new standard for an upturn when there will be shortages of quality personnel. Operators will be able to identify qualified personnel and train those that don't yet meet requirements, providing more quality personnel to the industry.
Improved Cement Plug Placement Method Resulting in Reduced Rig Time
Authors: Ahrenst A. , Grosshans C. , Martinez Melo A. , Suarez Jerez S. C.
Published: January 2016

Setting of cement plugs is generally perceived as a straightforward concept and simple operation. In reality, successful placement of a cement plug continues to be more difficult than traditionally thought due to the increasing challenges in extreme drilling environments. In today’s deepwater environment, plugs are often set at depths in excess of 30,000 ft and lengths of 1,500 ft and even longer. Despite significant progress on how to simulate cement plug placement, there may still be uncertainties as to the downhole parameters such as openhole geometry, lithology, pore and fracture gradients, depth of loss zone, downhole mud properties, and fluid design limitations for spacer and slurry. Due to these uncertainties, it may not always be preferable or even possible to set a plug using the traditional balanced plug technique. An alternative plug-setting technique that has been used successfully for many years is the internal blowout preventer (IBOP) method for which all the cement is placed into the annulus before pulling out of the plug. In this study, we analyze the advantages and disadvantages of the IBOP method. We also analyze field examples on an improved technique similar to the IBOP method, which, in this paper, is referred to the modified IBOP method. This method has all the advantages of the IBOP method while allowing for the use of mechanical separation of fluids, which is critical to control downhole contamination, especially for small and deep-set plugs.
A New Method to Mitigate Annular Pressure Buildup by Using Sacrificial Casing, Case Study: A Deepwater Well in Indonesia
Authors: Rizkiaputra Ricko , Siregar Ronny , Wibowo Teguh , Mabunga Shodji
Published: January 2016

For the subsea wells, the only accessible annulus is the annulus between production tubing and production casing or liner. When trapped annular fluid heats up, the fluid expands and will increase the annular pressure. Should the annulus between the surface and production casing gets trapped, the pressure buildup on this annulus would put the integrity of the well in jeopardy.

In this study, the tubular design approach is used to mitigate the annular pressure buildup by utilizing a section of lower grade casing installed on the outer casing (sacrificial casing) that immediately covers the inner casing being protected and keeps its integrity intact.

In selecting the sacrificial casing, three main parameters are needed, these are; the reservoir condition, formation characteristic, and wellbore configuration. These parameters are fed to a wellbore thermal simulator/stress analyses software, in order to create the well model with related pressure and temperature conditions. Iterative annular pressure buildup (APB) analyses throughout the life cycle of the well are then conducted in order to determine the suitable properties of the sacrificial casing. If the property of the sacrificial casing satisfies all expected loading conditions and protects the inner casing string, the design is deemed acceptable and the sacrificial casing becomes a part of the final well configuration.

This case study uses a deepwater well in Indonesia in order to apply the sacrificial casing method to mitigate the uncontrolled APB between the 20″ surface casing and 13 5/8″ production casing. A 20″ 154ppf X-56 section was selected as the sacrificial casing. In order to evaluate the effectiveness of the sacrificial casing throughout the life of the well, the various well scenarios covering the drilling operations, production operations and worst case discharge (WCD) events were evaluated. The simulations were conducted using proprietary commercial software having wellbore thermal simulator/stress analyses capability. This study suggests that utilizing a sacrificial casing to mitigate uncontrolled APB is sound engineering approach to keep the well integrity intact.
A Method for Determination of Stress and Fatigue in Risers and Wellheads
Authors: Horn Harald , Saasen Arild , Skogvang Arnljot
Published: January 2016

The paper presents a new and novel non-destructive method for measuring deterioration and cracks in steel structures. Results from stress and fatigue tests with different full scale structures are presented and related to real applications with respect to life-time prediction. Conventional cyclic loading test of riser-pipe elements are documented herein for confirmation of the method.

The subject method functions as follows: The material properties magnetic permeability and electrical conductivity, and changes in these, are determined by analyzing the measured voltage response to injected electric pulses. The response is transient voltage drop signals, measured under various conditions, and is the basis for calculating parameters representing the stress, fatigue and crack nucleation and crack development in the materials. The degree of material degradation can be used to calculate operational lifetime.

The method has been tested and verified for different types of stress and fatigue loads in different steel alloys. High sensitivity to elastic stress and early detection of permanent changes for high-cycle fatigue testing have been demonstrated with fatigue tests of workover riser pipes. High sensitivity to remanent stress, i.e. the steel's ability to "remember" stress (elastic) is a feature that is proportional to the maximum stress occurred since last measurement. On risers, measurement devices can be installed to give the actual condition of the steel for the most exposed locations. Additionally, this information can be used to calibrate the mathematical models for estimating the condition of the whole riser in order to reduce the uncertainty of estimates.
A Challenging HPHT Operation Supported by Dynamic Real Time Simulation, Forecasting and 3D Visualization
Authors: Nabavi Josef , Rommetveit Rolv , Wessel Just Sverre , Scott Laurie
Published: January 2016

Dynamic Real Time Simulation, Forecasting and 3D Visualization was utilized extensively in support of a very challenging HPHT drilling operation in the Norwegian Sea. The well was a vertical exploration well in the Haltenbanken area.

In preparation to the operation, an advanced training session was performed using a dynamic downhole training simulator linked to a topside rig simulator, for training of the drilling teams.

A real-time link was established with the operation, and WITSML data in addition to all well, fluid and string data was streamed into a dynamic, real-time simulation system. This simulation system provided the following; RT dynamic modelling of the pressure (ECD) and temperature profile in the wellbore; the cuttings distribution and its effects on the ECD;Automatic look-ahead simulations of ECD and temperatures on the fly was performed with the calibrated models as support for decisions.RT profiles of simulated versus measured pressure at the PWD, and simulated versus measured standpipe pressureRT dynamically updated 3D Visualization of the downhole wellbore with a continuously updated risk picture made available for the drilling teams.

Seamlessly linked to the RT system was a sophisticated what-if and planning model. 24 hour forecasting of operation was provided every day, and this gave a very good indication of future possible operational impacts. In addition to 24 hours forecasting, pre-planning simulations of upcoming sub-operations as well as what-if simulations on the fly were performed. The results from these simulations were used to update the risk register and made available in the 3D Visualization window.

Three specific cases will be discussed in the paper; Pre-simulation of running the 9 7/8″ casingPre-simulation of cementing the 9 7/8″ casingRT modeling of ESD in case of mismatch between rig calculated and measured values

In these cases the simulations provided valuable results which increased the risk awareness and prevented problems.

The paper will also discuss the RT 3D Visualization and its impact on reducing risks and communicating the dynamic risk picture.

The total simulation system with infrastructure, models and challenges will also be presented.

The operation was successful, and the results from the simulation system was a contributor to this.
A New Sour Service 125 ksi SMYS Drillpipe with Sour Service 120 ksi SMYS Tool Joints for Use in Sour Gas Drilling or Non-Sour Offshore Intervention Riser Applications Requiring Higher Load Capacities
Authors: Hehn Lucien , Uttecht Amie , Jellison Michael , Sanclemente Leianne , Delahoussaye Mike
Published: January 2016

The term "sour" is used to refer to drilling environments containing hydrogen sulfide (H2S). In sour wells, H2S causes sulfide stress cracking (SSC) in carbon low-alloy steels under tensile stress. A form of hydrogen embrittlement, SSC causes sudden, brittle fracture in drillpipe. To combat the effects of H2S exposure, sour service drillpipe has been manufactured to meet IRP Volume 1 - Critical Sour Drilling specifications. IRP requires 75 ksi (SS75), 95 ksi (SS95), or 105 ksi (SS105) tubes with all three grades using 110 ksi SMYS tool joints for use in sour operations. However, these lower yield strength IRP grades have limited load capacity which restricts drilling parameters such as total depth (TD) and margin of overpull.

Using advanced steel heat treatment methods, a 125 ksi SMYS grade sour service drillpipe has been developed. The 125 ksi tube is mechanically incompatible with the standard 110 ksi IRP sour service grade tool joint because of the large difference in yield strength between the two components. Therefore, a new class of sour service tool joint with an SMYS of 120 ksi was required for the 125 ksi sour service tube. This new higher yield strength tool joint needs to meet the same level of SSC-resistance as the 110 ksi IRP tool joint, i.e., pass testing in solution A method A of NACE TM0177 (100% H2S @pH = 2.7, 720 hour test) at a testing stress of 65% of SMYS. Like the high yield strength 125 ksi tube, advanced heat treatment methods were required to achieve SSC-resistance in the higher yield strength tool joint.

A second application for the 125 ksi drillpipe is as an offshore drillpipe-based intervention riser for non-sour wells. Currently, 105 ksi drill pipe grades are often used but increased demands on load capacity (up to 1,000 kips) makes the 125 ksi drillpipe an attractive alternative. The 125 ksi drillpipe also meets recommended hardness limitations placed on offshore risers in specification API RP 17G (Recommended Practice for Completion/Workover Risers).

This paper introduces an SSC-resistant 125 ksi drillpipe with SSC-resistant 120 ksi tool joints and presents the results of NACE TM0177 testing of this new technology. The new 125 ksi drillpipe will allow for increased load capacity over IRP SS105 ksi grade drillpipe in drilling environments with moderate to low concentrations of H2S. In addition, it can serve as an improved substitute over 105 ksi drillpipe-based offshore intervention risers due to its increased load capacity and controlled hardness.
Long Reach Well Concept
Authors: Stokka Sigmund , Cayeux Eric , Gardner David , Kragset Steinar , Lohne Hans Petter , Randeberg Erlend , Skadsem Hans Joakim , Aas Bjarne , Kyllingstad Henrik , Larsen Torgeir , Saasen Arild
Published: January 2016

Current Extended Reach Drilling (ERD) well technology limits the well lengths to roughly 12 km with a horizontal departure of approximately 10 km. This paper presents a concept that enables simultaneous drilling and completion with an aim to substantially extend well reach and with an ultimate objective of constructing 30 km long production wells. Longer reach wells can be used to drain remote reserves using existing production facilities, as well as provide a means to access reservoirs located beneath environmentally sensitive areas.

The key technology elements that enable the concept to construct long reach wells are multiple sliding packer traction units in combination with a dual casing drilling system, comprised of a casing with an inner tubing. The sliding packer traction units provide two primary functions; continuous well control along the length of the borehole and traction to overcome axial friction. In addition, the traction packers provide a stable bottom-hole drilling platform avoiding the occurrence of drilling instabilities such as stick-slip, which can damage conventional bottom-hole assemblies and the drill bit in particular. The dual casing provides the conduit for drilling fluid circulation to the bit and cuttings transport to surface. The drilling fluid is pumped through the annulus formed between the casing and inner tubing. The drill cuttings are transported to surface through the inner tubing, ensuring efficient cuttings transport with a low-pressure loss.

The concept has been developed through a five-year project, kicked off in 2010. A prototype has been built and tests have shown that each sliding packer traction unit is able to push the drill bit or pull a completion string with a large axial force in excess of the estimated requirement. In the paper, elements of the system are described in detail and the results of the full-scale yard tests are presented.

The concept represents a new well construction method incorporating advanced completion technology. It enables drilling and completion of long reach wells and can operate in areas with complex pressure regimes, such as can occur from pressure depletion due to production or pressurizing as a result of the injection of water or gas. Well control is provided by packers placed in pairs that seal off the annulus at predefined intervals along the drill string. Production takes place through a large inner diameter. It is a well construction method with no flat time.
An Instrumented Topdrive Sub System: Enabling Greater Drilling Efficiencies via Innovative Sensing Capabilities
Authors: Bryant Thomas M.
Published: January 2016

While innovations and advances in drill rig and downhole drilling technology have enabled operational efficiencies and productivities in drilling far beyond that achieved even a decade ago, a large proportion of drill rigs today still lack suitable instrumentation that can be utilized to achieve a higher level of drilling performance. Operating with the disadvantages associated with inadequate, inferior, sometimes poorly maintained, and often uncalibrated rig sensors, these rigs are unable to achieve the efficiencies increasingly being demanded by operators and owners. To address this situation, a single point of service has been developed that contains a suite of calibrated and accurate surface rig sensors for acquisition of measurements essential for operations such as drilling optimization. These sensors, housed within an instrumented surface sub, include block height; drillstring tension, torsion, bending moment, bending angle, and rotation speed; mud flowrate, density, pressure and temperature; and drillstring vibrations. The sensor measurements are direct, calibrated, acquired simultaneously at user-configured sampling and recording rates, and possess degrees of accuracies well beyond those of standard rig instrumentation.

Utilizing aerospace, medical, industrial, and proven oilfield technologies, such as acoustics, laser range finding, thin-film strain gages, and product miniaturization, an instrumented sub system is being developed to provide for direct acquisition of the most critical measurements required for drilling optimization. The sub was designed to be located at the top of the drillstring. Primary design considerations included high accuracies of measurements, with traceability of calibrations; simultaneous acquisition of all measurements; preservation and extension of battery life via sophisticated sensor and battery management; very low bit error rates and robustness of radio telemetries; and ease of use tied with flexibility of user customizations.

Early and limited testing of the system indicates accuracies of measurements of hookload, torsion, bending moment, rotation speed, pressure and temperature to be in the range of 1% or better. While characterizations of accuracies for the laser-derived height measurement, volumetric flowrate, and mud density are in the process of being determined, these measurements are innovative and enabling with respect to the unique location in which they are sensed. The acquisition of synchronous measurements facilitates and enhances processing, manipulation and ultimate interpretations of mixed data. Data are telemetered wirelessly from the sub to a surface-based computing and display device via a robust radio communications channel designed and being tested for bit error rates of <1/10,000.
Integration of Time-Based Dynamics Simulation with Milling and Underreaming System to Implement Reliable Single Trip Solution in Plug and Abandonment Operation
Authors: Wang Yaou , Vos Marco , Karimpour Alireza , Fearn Murray , den Besten Hendri , Stanko Tomasz , Bain Jim , Shen Yuelin , Stokes David , Issa Ali , Khan Zafar
Published: January 2016

A trip-saving well abandonment technology was recently developed to prepare wellbores for the installation of abandonment barriers where poor annular cement quality exists at the required plug location. The trip-saving technology uses a hybrid section milling and underreaming single-trip BHA design to remove casing from the wellbore and underream to virgin formation, eliminating all potential leak paths from the cement barrier. This single-trip BHA is a step change in conventional industry practice whereby the service is typically provided in two dedicated trips: one to mill and one to underream. This paper presents the successful application of the single-trip BHA with the aid of a time-based simulation system in a challenging environment.

The single-trip BHA was required by an operator in The Netherlands, where challenging well conditions and abandonment requirements resulted in the need for underreaming to a 20-in hole size from a wellbore tool restriction OD of 8.5-in. This ultrahigh-ratio reamer arm opening generates significant dynamic loadings on the BHA. To achieve a successful single-trip operation, a 3D time-based drilling dynamic simulation system was employed as a technical solution to ensure: Maximum ROP to meet customer requirements while balancing with BHA limits of operation.Intended underreamer behavior to create a concentric and balanced hole opening across the full hole profile.

The dynamic simulation first carried out a prerun parametric sensitivity study to identify the optimal parameters with high ROP and low vibration/stick-slip ratio. Then the underreamer off-center distance was examined to ensure sufficient new virgin rock exposure in all directions for subsequent cement plug setting.

This dynamic simulation outcome was the creation of a prejob planning roadmap which enabled the job to be executed seamlessly at the rig site whilst achieving the customer Plug and Abandonment (P&A) objectives and ensuring the optimal utilization of each component of the single-trip BHA. The prejob planning roadmap was calibrated against operational performance by recorded stable operation data, observed good reamer arm dull conditions, and good caliper-logged hole quality. In addition, the field data were found to be highly in line with the simulation predictions, validating the accuracy of the time-based dynamic simulation system.

The single-trip operation saved the operator more than 49 h of rig time in abandoning the well. The successful application demonstrated the capability of not only the single-trip BHA, but also the calibrated dynamic simulation which saved substantial rig time and delivered a reliable single-trip service. The the successful operation not only reduced operator costs, but also reduced HSE exposure with less BHA handling on the rig floor.
Field Performance of Automated High-Speed Mud Pulse Telemetry System
Authors: Emmerich Wojciech , Akimov Oleg , Brahim Imed Ben , Greten Alexander
Published: January 2016

Present logging-while-drilling (LWD) technologies have substantially increased the amount of information collected downhole. Mud pulse telemetry (MPT) is the core real-time data transmission technology in the oil industry, and it must deliver answers while drilling with equal log densities despite the increased number of services. Ultimately, faster real-time data rates are required when a compromise between rate of penetration (ROP) and log density is not an option. In particular, when using high-density and high-plastic viscosity oil-based muds in deep wells, transmitting data at high rates presents challenges due to the harsh transmission channel conditions.

We describe improvements to the MPT system, enabling reliable data transmission with physical data rates of 10bits/s and higher. Special signal sequences are used to automatically adjust adaptive filters. The pulser sends out the sequences regularly, enabling the surface system to tune the adaptive filters for changing channel conditions. The filter performance is tested and saved into a data base with quality indicators, empowering field personnel to optimize decoding quality through better decision making. Enhanced signal processing algorithms on the surface significantly increase the success rate of this automated system, as well as improve the decoding quality and reliability.

This improved MPT system has been effectively run in challenging fields in different regions. The system has achieved improved operational performance and higher system reliability compared to offset runs. Complex bottomhole assemblies (BHA) with many LWD services can be deployed with outstanding data density and no ROP reduction. Its ease of use enables the increase of real-time data rates and timely decisions when decoding quality indicators start to decrease. Furthermore, the new system introduces higher automation level, which allows the field service engineer to concentrate on delivering more answers to the operator.

By enabling high-speed data rates in a wider variety of environments as well as higher data rates in standard settings, the improvements in MPT increase the safety while drilling and lower the overall cost of drilling wells.
Team Approach to Horizontal Drilling Optimization in the Marcellus Delivers Record Setting Performance
Authors: Livingston Denise Azuaga , Andes Drew , Czerneski McKenna , Bauer Scott , Castro Boris , Gorr Kevin , Coffman Ryan , Beebe Luke
Published: January 2016

The Marcellus tight gas shale formation in the northeast Appalachian region of the USA represented 40% of total domestic production in 2014 and 2015, and is strategically positioned close to its gas demand. To increase production and improve well economics, operators are drilling from multi-well pads, requiring complex well profiles. This is driven by local logistics and environmental requirements. This paper will discuss the main drilling challenges faced by one operator and their directional drilling provider, while drilling more than 1 million feet in this area, and the evolution of effective drilling practices including bit and bottom hole assembly (BHA) design, drilling parameter optimization and reservoir navigation techniques. This resulted in the achievement of a drilling record of a mile a day on the most recent pad.

Typically steerable motor assemblies require multiple runs to drill the curve and lateral sections of a directional well. Different formations in the curve may yield different build-up rates (BUR) requiring close attention to well planning and execution to land in the target zone. Longer laterals for optimal lease development may cause undesirable torque management issues. A drilling system with near bit inclination capability and near bit gamma is ideal for TVD control to stay in the producing target zone. Recent advancements in rotary steerable systems (RSS) have resulted in high build-up rate designs that meet these requirements. To address these challenges, the operator, engineering and service companies created a drilling program for eight wells with the objective of drilling the 8¾-in hole section in one run, including 3D well profiles, matched bit and BHA designs, optimized drilling parameters for each curve and lateral portions of the well, and reservoir navigation techniques. The 8¾-in hole section length ranged from 4,400 to 14,700 ft including curves varying from 8°/100ft to 10°/100ft and an average lateral section length of 9,700 ft.

The results of this team approach and optimized drilling program delivered improved rates of penetration (ROP) by 10% compared to previous pads and an average of 1.12 runs per well. The two most recent wells set drilling records of a mile in a 24 hour period resulting in 31% and 30% reduction in drilling time while staying 100% in the target zone compared to 97% average from previous pads. This successful collaboration between all parties involved resulted in optimized drilling time, reduced operational costs and financial predictability and consistency. The authors will explain the process used and show examples of this outstanding drilling performance using case histories from the program in the Marcellus shale play.
Swab and Surge Pressures with Reservoir Fluid Influx Condition during MPD
Authors: Samuel Robello , Lovorn Randy
Published: January 2016

With managed-pressure drilling (MPD), there is a need to have precise control on the profile of annular pressure while drilling and cementing. However, current methods using conventional calculations for controlling bottomhole pressures in MPD wells do not properly take into consideration the elasticity of drillpipes under reservoir fluid influx and, therefore, do not control the proper pressures. For these reasons, a method for more precisely controlling the annular pressure profile throughout the wellbore is required. The purpose of this study is to investigate the dynamic motion of the drillstring when there is an influx of formation fluid, with particular interest focused on the effect of bottomhole pressure. Increased underbalanced and managed-pressure drilling operations have necessitated predicting wellbore pressures more accurately, as they allow for reduced fluid loss and reservoir influx. While drilling through or reciprocating in a potential reservoir zone where the borehole and formation fluid pressures are in a narrow margin under a managed-pressure condition, the swab pressures may cause the wellbore to be underbalanced for a small period of time.

At certain times, an incremental influx for a short duration may be potentially detrimental. Neither the steady-state model nor the transient model is comprehensive enough to predict the wellbore pressures correctly, as both models neglect the reservoir fluid influx or fluid loss under this condition. This paper presents a coupled swab/surge model, whereby the wellbore bottomhole pressure can be predicted more accurately with a reservoir fluid influx. A full balance of mass and momentum for pipe and annulus flow is solved. The model also includes the effects of fluid inertia and compressibility, wellbore elasticity, axial elasticity of the pipe, and temperature-dependent fluid properties. The transient-gas reservoir model allows for investigating the effect of produced gas when the formation pressure exceeds the bottomhole pressures. This model allows for measuring the influx as a function of pipe movement and predicting the amount of influx as a function of time.

The practical usefulness of the theory, backed by the fundamental analysis, is demonstrated with numerical cases. The effects during underbalanced conditions have been analyzed, and several non-intuitive transient effects, such as the observation of reduction in surge effects while swabbing and vice versa, are highlighted.
Deepwater Tieback Cementing Design Challenges and Engineering Approach - Gulf of Mexico Case Study
Authors: Elhancha Anouar , Dooply Mohammed , Koons Brian , Saleh Muhammad
Published: January 2016

The Gulf of Mexico post-moratorium well design requirements became more stringent after the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) imposed the worst-case discharge (WCD) criteria. The conventional design configuration of nested liners does not always allow meeting the WCD criteria and the long string configuration presents operational limitations.

Tieback casings and liners, on the other hand, enable reaching the well objective while meeting the WCD criteria. However, tieback casings and liners present several operational challenges during the well construction phase, such as casing design, hardware selection, running in the hole and cementing.

Cementing design challenges, include defining the optimum top of cement (TOC) to mitigate annular pressure build-up (APB), managing high placement pressures resulting from tight annular clearances to prevent damages to casing hardware, optimizing centralization and fluid properties for safe cement placement and effective mud removal, and estimating hook load variations during cement placement to prevent premature release of the running tool.

This paper will mainly focus on the above cementing design challenges and discuss the engineering techniques used to approach them. The first part of the paper will review the limitations of current cementing design tools in tieback configurations. The second part presents the applications of and key learnings from engineering techniques to overcome the limitations in cementing design to achieve better cement placement and effective mud removal. Two case studies from Deepwater Gulf of Mexico will be presented.
New Wireline Extreme Pull Systems Reduce Gulf of Mexico Deepwater Fishing Incidents Saving Operators 12 Days of Deepwater Rig Time and USD 9 Million
Authors: Fisher Bill , Daugherty William T. , Sarian Serko , Tucker Jim , McManus Dacey , Babin Chris , Varkey Joseph , Dalhami Issa Al
Published: January 2016

The combination of a newly developed extreme-tensile-strength steel wireline cable armor and polymer encapsulation technologies has recently created a second generation of low-torque, extreme-strength wireline cables. The high-pull system is complemented with high-capacity winch units for surface data acquisition, tension-relief capstans, and downhole well accessories. The resulting surface pull capacity of wireline conveyance reaches 26,000 lbf, a 25% increase over the strongest system available previously.

When the 21,000-lbf system was introduced in 2010, deepwater fishing incidents dropped to less than 1% of total descents. However, with 3 days per fishing operation, associated deepwater fishing time remains high. The new high-pull system has been deployed in the Gulf of Mexico since October 2014. Pulls exceeding 21,000 lbf made it possible to prevent four instances of otherwise unavoidable fishing incidents, saving more than 12 deepwater fishing days and USD 9 million of rig time. In 2015 Gulf of Mexico fishing incidents have dropped to a record low 0.4% of total descents.
Efficiently Transferring and Sharing Drilling Data from Downhole Sensors
Authors: Baumgartner Theresa , Zhou Yang , Oort Eric van
Published: January 2016

The drilling industry has begun to cherish the value of data collected from downhole sensors, often gathered at high frequencies. Moreover, it has started to capitalize on the availability, analyses and credibility of this data through step-changing knowledge gains that have enabled meaningful drilling performance improvements. As a result, topics like data quality, data ownership, and data integration are now routinely being discussed among stakeholders as data from downhole memory tools slowly starts to integrate into routine well planning and optimization workflows.

The collectors of data usually are not the sole owners and main beneficiaries of such data. Large amounts of data have to be transferred from service providers to various collaborators within and across companies. The process of agreeing on a data format, relevant accessory information and means of transfer, is currently laboriously repeated on a project-by-project basis. This practice not only consumes unnecessarily resources on both ends, but also carries the risk of losing crucial contextual information. WITSML standards are often unsuitable for large high frequency data files and do not provide enough flexibility for certain contextual information.

This work proposes a file format suitable for securely storing downhole data and sharing it across all stakeholders, providing both flexibility and simplicity. The proposed file format implements a set of specialized horizontal and vertical dividers to structure contextual information on the well, the run, and the sensors, and to store them in the same file as the measurements. Among other things, well and section information, responsible personnel, equipment and sensor properties, time calibration, and operational parameters may be specified. The inclusion of both required and optional inputs ensures both flexibility and essential context, and allows the coverage of a variety of applications. It is comparable to the Log ACSII Standard (LAS) file that quickly found wide acceptance in the well logging community and beyond after its introduction in 1990.

The implemented dividers enable the data files to be easily accessed by variety of programs and comfortably viewed by the human eye using any standard spreadsheet or text file application. Importing and exporting applications can be provided to the users, who can then easily produce these files from raw data for transfer, or integrate them into existing data management systems.

Stakeholders, such as operators, service companies, and tool manufacturers are involved with the creation of this standard file format to ensure consent amongst all users. The standardization of downhole sensor data files proposed in this work marks an important step towards automated analysis of downhole data, reduction of data loads, and data integration. Our approach is illustrated using various examples of how the new standard can be applied on actual field data.
A Deepwater Openhole Gravel Pack Completion with Prolonged Well Suspension without Initial Cleanup: An Angola Block 15/06 Case History
Authors: Staltari D. , Urdaneta J. , Barradas O. , Pellicano’ D. , Ripa G. , Fernandes P. , Cauende C. , Sonangol E. P. , Nasrallah M. M. , Aye Y. A. , Djouli L. B. , Adeolu A. I. , Magloire B. A. , Kumar A. , Gadiyar B. R. , Parlar M.
Published: January 2016

Most of the deep water reservoirs in Angola are weakly consolidated sands, requiring sand control, and openhole gravel packing is one of the most widely used sand control techniques in the area, Block 15/06 being no exception. High inclination wells targeting multiple reservoir sections interlayered with reactive shales, relatively low frac window, and prolonged well suspension without well cleanup were some of the challenges that needed to be addressed to ensure completion integrity and well productivity.

This paper presents the measures taken during the design and execution phases to address the project challenges, along with an evaluation of completion integrity and well performance. Analysis of the downhole gauge data is detailed for one of the wells as an example, illustrating the importance of including downhole gauges in the completion.