bluuebunny/crossref_metadata_2025 huggingface dataset:
Addressing and Managing Cyber Security Risks and Exposures in Process Control
Authors: Pitzer Darrell R. , Girdner Ana M.
Published: June 2014

Management of cyber security risks and exposures in the industrial process control environment has emerged as an important and dynamic element in the operational safety, security, and reliability of the infrastructure in the oil & gas industry. In the last 10 years, the number and complexity of cyber security intrusions and malware infections has exponentially increased. In 2010, the entire threat landscape changed with the appearance of Stuxnet, which demonstrated that targeted attacks to control systems were not only possible, but very likely and very hard to defend.

This has prompted the industrial and commercial sectors to develop and continuously improve cyber security policies, programs, and procedures to address and manage the risks and exposures associated with these threats. Similarly, government sectors have launched programs, enacted cyber security laws, and developed policies, procedures, and standards to address the steadily increasing threats and vulnerabilities in the industrial control systems area.

The connected, digital oil field must include comprehensive and robust controls to protect against these risks and exposures. It requires continuously evolving and improving cyber security programs, and requires diligent, ongoing management to address evolving and advanced persistent threats.

This paper will provide an oil and gas industry insight into cyber security programs and countermeasures, and will share ExxonMobil’s* approach to cyber security in the industrial process control environment.
Permanent Downhole Flow Metering Improves Reservoir Management in Subsea Environment: A North Sea Case Study
Authors: Akil Ihab , Das Kaushik , Yunusov Manuchehr , Figueroa Martin
Published: June 2014

Development of remote offshore fields has unique technical challenges because quite often, such fields have only a few subsea wells tied to adjacent fields. This scenario is especially the case in small and/or marginal offshore fields where the profitability is very dependent on capital and operational expenditures. Therefore, quite often a group of marginal offshore fields located nearby are developed together with several gathering points and pipeline systems joining different subsea wells. Flow metering is usually performed at gathering points on the seabed using multiphase flowmeters rather than at individual wellheads. While this method can be very efficient from an economical point of view, it may, on the other hand, compromise the data acquisition process, resulting in an insufficient understanding of individual well performance. The situation may get even more complicated when wells from different fields are tied together. Because well interventions for individual well performance evaluations are generally expensive and not always possible, it is necessary to have a reliable and cost-effective permanent downhole monitoring system that provides continuous real-time data necessary for updating and improving the field development strategy.

This paper presents a case study of a subsea oil producing well in the North Sea where one such system—a venturi downhole flowmeter—was installed to obtain continuous pressure and temperature measurements for downhole fluid density and flow rate calculations. This type of flowmeter is useful only in liquid environments because the underlying Bernoulli principle is applicable only for single-phase flow and tenable in low-slip liquid/liquid flow regimes, such as in the concurrent flow of oil and water at high velocities. Surface flow rate validation is always a good complement but not compulsory. The goal of this cost-effective monitoring method was to facilitate production (oil and water) allocation so as to simultaneously improve well performance and reservoir modeling.

The continuous pressure and temperature data obtained from this downhole flowmeter were translated into valuable information during well flowing and shut-in periods. The application of specific workflows transformed the downhole data into fluid flow rates, which allowed to accurately evaluate performance of the well. Successful calculation validations were performed using a multiphase meter data due to the inability to test the well. The results allowed the operator to properly allocate flow, assess reservoir performance, and identify improvement opportunities in the field-development plan.

This case study demonstrates that with the installation of reliable, cost-effective downhole flowmeters and the appropriate interpretation of downhole real-time data, well performance evaluation and reservoir management strategy can be improved simultaneously in subsea environments where the risks are high and expenditures are tight.
Characterizing Drilling Applications and Bit Designs Using Common Responses Improves Bit Selection Outcomes
Authors: Russell S. Craig , Vempati Chaitanya
Published: June 2014

This paper describes methods to relate drilling applications and PDC bit designs to a comprehensive set of common responses, or behaviors. The responses are quantifiable, measurable, and relatable to an audience with a wide range of technical expertise. The methods improve bit selection outcomes by focusing on application requirements in light of bit performance capabilities instead of traditional methods focusing on bit features such as cutter size, blade count, and gage length.

The common drill bit responses described in this paper are aggressiveness, cleaning efficiency, lateral stability, torsional stability, side cutting aggressiveness, bit durability, cutter abrasion resistance, cutter impact resistance, and cutter thermal stability. Technical methods were developed to characterize drilling applications and bit designs independently for each response. The heuristic application characterization methods draw from proven knowledge and a broad base of expert experience. The empirical bit characterization methods are derived and validated from more than a decade of laboratory testing, field performance, and computer simulations.

The methods are demonstrated using a software tool that captures application requirements and searches for suitable bits in a comprehensive bit design database. A multi-parameter fit function returns a sorted list of all bits in descending order of their match to application requirements. The optimum bit is then selected by performing a more thorough response-by-response comparison. A case study is presented to demonstrate the functionality of the system. The results yield an improved understanding of the application, resulting in faster and improved bit selection.

The common response approach described in the paper is a breakthrough method to continuously improve bit selection by driving greater fundamental understanding of application requirements and bit capabilities. The common response terminology enables easier communication between users such as geologists, design engineers, field personnel, and drilling operators. In addition to matching bit designs to application requirements, the approach also enables efficient application and bit comparisons. Furthermore, the system framework is sustainable as technology evolves and application priorities change.
First Application of Turbodrill and Hybrid Bit to Optimize Drilling Times in Cretaceous Formations with High Chert Content in Mexico South Region
Authors: Varela R. , Guzman F. , Cruz D. , Atencio N. , Iturrizaga F. , May R. , Solano R. , Perez R.
Published: June 2014

This paper highlights the design, execution, and evaluation of the first application of turbodrill and hybrid bit to drill cretaceous formations with up to 40% chert content in Mexico South region. The complex cretaceous formations in the Terra field presents many drilling challenges: mud losses, gas influxes, hard [Unconfined Compressive Strength (UCS) 15 – 30 ksi] and abrasive formations, difficulty building inclination, low rate of penetration (ROP) requiring many runs of 8-½" tungsten carbide insert (TCI) bits.

The goal of a new drilling system application was to reduce trips for TCI bit changes due to drilling hours limitations, optimize flat times, reduce rotary steerable system (RSS) failures, deliver a wellbore with minimal tortuosity to enhance wellbore evaluation and running liner operations, and eliminate the risk of fishing for lost cones.

To meet these objectives the use of turbodrilling and hybrid bit technologies was evaluated. Hydraulic simulations were run to determine if the mud pumps could deliver the required hydraulic power to the turbine, a drill string design was performed to avoid fatigue failures and increase on-bottom rotating hours in a high temperature environment, directional requirements were analyzed to estimate the dogleg severity (DLS) in carbonates with chert nodules to be able to reach the proposed well objective.

The turbodrill and hybrid bit application drilled 1240 ft, which is the longest run in the field eliminating two trips when compared with TCI bit runs. The turbodrill application successfully built inclination and turned the wellbore at the planned DLS. Additionally, increased service life of the managed pressure drilling (MPD) rotary head and top drive washpipe was observed. Casing wear was reduced due to the low drill string revolutions per minute (rpm) on surface which was corroborated with the low amount of steel recovered in the shale shakers magnets. Trips to surface were without drag and 7" liner was run immediately after logging, eliminating a wiper trip.

The Terra field has an aggressive development plan and lessons learned from this application will reduce drilling times and meet regional objectives to boost production from hard carbonates reservoirs. Horizontal wells are now being drilled, turbodrills and hybrid bits demonstrated to be viable solutions for this technical challenge in southern Mexico region.
Effect of Temperature on the Compressive Strength of Eagle Ford Oil Shale Rock: An Experimental Study
Authors: Emadi Hossein , Soliman Mohamed Y. , Samuel Robello , Harville Don , Gamadi Talal D. , Moghaddam Rozbeh B.
Published: June 2014

Although many shale oil wells have been drilled recently in the Eagle Ford shale oil field, wellbore stability problems in the shale oil reservoirs have not been fully understood. During drilling, fracturing, and production operations, the wellbore temperature is not constant but varies during these operations. This temperature fluctuation results in thermal cycling which tends to alter rock physical properties such as compressive strength, Young's modulus (E), and Poisson's ratio (ν), and consequently, result in wellbore stability problems. Wellbore stability problems are one of the most costly problems that can occur during drilling operations, especially in unconventional reservoirs. These problems include but are not limited to tight holes, pipe sticking, fishing, sidetracking, and well abandonment. Since the majority of wells are drilled horizontally in shale oil reservoirs, the likelihood of wellbore stability problems is dramatically increased. Thus, to have more efficient and effective drilling operations through these formations, a better understanding of their properties as well as the effects of drilling conditions on rock properties such as compressive strength, Young's modulus (E), and Poisson's ratio (ν) are required.

Not many experiments have been performed to investigate the effect of temperature on sedimentary rocks' properties such as compressive strength. Some experiments have been conducted to assess the effect of temperature on shale rock samples, since shale oil rock samples are quite different from common shale rock samples, the results cannot be equally applied to shale oil and shale gas formations.

For this study, the mineralogy of shale oil core samples from the Eagle Ford field was determined. To simulate actual well conditions a High Pressure High Temperature (HPHT) setup was built and used which let us apply different axial and radial confining stresses, equivalent formation pore pressure, and drilling fluid wellbore pressure. The experiments were conducted under elevated temperatures to better mimic real drilling operations. Saturated shale oil core samples from the Eagle Ford field were tested under various temperatures including reservoir temperature. We also performed Unconfined Compressive Strength (UCS) tests to investigate the effect of temperature on the compressive strength of the core samples. The experimental setup was modified to accommodate five Linearly Variable Displacement Transducers (LVDTs) to measure Young's Modulus (E) and Poisson's ratio (ν). Various experiments were run to quantify the effect of temperature on the rock compressive strength, E, and ν. Experiments have shown a distinct change in the mechanical properties of the rock. These effects will be discussed in details.
Case History: Casing Collapse During Concentric Drilling Operation Leads to New Casing Design Approach for HP/HT Wells with Low Reservoir Pressure and/or N2 Injection
Authors: Medina Mauricio Güiza , Bedino Henry , Sierra Sebastian , Scagliarini Stefano , Romero Daniel , Rocha Raphael , Rosas Reginaldo Rodriguez
Published: June 2014

This paper describes the events leading to the collapse of a 9 7/8" liner over a 7 5/8" casing while drilling a depleted fractured reservoir (high inclination, 150°C BHST) using the concentric injection technique and Managed Pressure Drilling (MPD) in well "A" in the South of Mexico. It also illustrates the investigation process conducted aimed at the identification of the potential failure scenarios. Finally, a new casing design approach for wells under these challenging conditions based on limit state design and deterministic load estimate has been developed and implemented as a result.
Dynamic Modeling of Gas Distribution in the Wellbore During Kick Situations: The Solutions
Authors: Gruber Claudia , Spoerker Hermann F. , Brandstätter Wilhelm
Published: June 2014

For decades, well control models have been based on the assumption of a more or less single-phase "gas bubble" present in the annulus and slowly migrating upwards after shut-in. While this approach satisfies straightforward volumetric well control aspects, it ignores solution and chemical reaction-kinetic effects. Especially when investigating sour gas (i.e. hydrogen sulfide) influxes into high-pH drilling fluid systems, the prediction of actual downhole pH development during shut-in and well-killing operations is of prime interest when deciding on potential damage to high-strength steel drill string components (> 110 ksi tensile strength) due to sulfide stress cracking (SSC). Several previous publications (Spoerker et al 2008, Spoerker&Tuschl 2010, and Spoerker et al 2012) have presented the progress of a multi-year research project dedicated to numerical modeling of the entry, distribution and upward movement of gas kicks in the wellbore and the impact of sour gas influxes on high-strength steel drill string components. These numerical simulations shall form the basis for subsequent modeling of the chemical reaction kinetics taking place in the wellbore and resulting in a buffering of the molecular hydrogen against the high-pH drilling fluid. Such chemical reaction kinetics modeling requires sound understanding of the active surfaces between the phases (phase interface area), the amount of energy in the system (thermal and kinetic energy due to the flow and fluid mixing characterictics) and the time available for the reaction to take place before any "native" reservoir fluid actually comes into contact with the steel surface. This paper presents the conclusions from this five-year research project and indicates directions for potential future research.
The Drilling Business Model: Driver or Inhibitor of Performance and Innovation
Authors: de Wardt John P
Published: June 2014

The drilling business model has recently become the "elephant in the room" as drilling systems automation advances seek an integrator and technology / performance enhancements seek rewards. The day rate model has been adapted many times over the life of the industry but none of these adaptions has prevailed.

The business model entails a number of key aspects that drive business behaviors in the supply chain; control, liability, risk, revenue. Some companies have the approach that the operations team drives the contracting of suppliers while others draw the whole process under supply chain for process control and pricing leaving the delivery of value often in significant doubt.

This paper describes many of the business model adaptions created over the past 70 years from footage and turnkey through Integrated Project Management and Production Enhancement Contracts. Recently, actions and intentions have surfaced to transpose roles within the drilling supply chain to overcome resistance to change and improve financial performance (vertical integration by operators). This paper makes observations on the various forms of contract and various roles in the supply chain. The conclusions outline a blueprint for developing a business model that can drive performance and innovation throughout the supply chain.

Discussing the current business models and opening the industry to development of more appropriate models has extremely high value and impact. It is a topic often raised and often left un-debated. If a new business model is broadly adopted it will change roles, performance, technology application and revenues throughout the supply chain. Awareness of this potential change will be extremely important to managers and engineers in the drilling business.
Effective Hydraulic Modeling and Field Data for Deepwater Horizontal Well with Low Drilling Margins in an Unconsolidated Formation
Authors: Mohan Raj , Boswell Betsy , Oyler Ken , Lim Kim , Luyster Mark , Williford Mike , Collins Natalia , Cheaney Richard
Published: June 2014

Effective hydraulic modeling to predict the equivalent circulating density (ECD) was highly critical for successful drilling of a pilot well in a deepwater development in the Gulf of Mexico. The drilling objectives included linking three reservoirs, divided by moderately thick shale at relatively high dip while upholding the properties between relatively narrow drilling margins. This difficult drilling environment mandated intensive reservoir drill-in fluid maintenance practices with specific focus on rheology, density, and optimization of bridging materials while reducing the incorporation of acid-insoluble solids.

The pilot, Well B, is one of a handful of horizontals drilled in ultra deepwater shallow BML, having over 2,000 feet lateral, that was successfully drilled in challenging 8,257 feet of deepwater in the Paleogene reserve at a shallow depth of 2,300 feet TVD below the mudline (BML) and the first well to be produced in this reserve development. Due to the shallow depth from the mudline and soft sediments, the drilling margins were extremely low – 0.7 lb/gal (i.e., 250 psi); thus wellbore stability analyses were critical in order to avoid unanticipated losses to formation, losses to mudline, influxes or borehole collapse. Despite the limitations of available offset data used as an analog, the pore pressure and geological fracture gradient were known. However, in comparison to offset Well A (3,800 ft BML) with pressure margins 450 psi, Well B realized a significantly reduced operating pressure window and shallower depth BML. The ECD, equivalent static density (ESD), downhole pressure, and flow rate were carefully monitored to enable drilling within the established operational window and increasing the success of attaining total depth. The meticulous monitoring was a key to the ability to successfully drill the lateral section with only marginal losses and no wellbore stability problems.

The paper presents the hydraulic modeling in addition to the field monitoring data as well as summarize the lessons learned from pilot Well B as compared with offset Well A.
First 30-In Casing Exit Enables Slot Recovery in Gulf of Suez's East Zeit Field
Authors: Reda Mohamed , Fahmy Mohamed , Khedr Mahmoud
Published: June 2014

To increase production in East Zeit field, the operator wanted to recover a slot occupied by a well with collapsed 30-in conductor. Because of platform constraints, driving new pipe was not an option. Attempts to mill through an obstruction at 600ft were unsuccessful. And because the collapse occurred below the window, it was not possible to recover the damaged conductor and sidetrack. A whipstock system was required that could anchor in the 30-in casing, enabling a full-gauge 16-in window to be milled for sidetracking. However, there are no whipstocks made with anchors large enough to set in 30-in casing.

To solve the problem, the service provider proposed running 600ft of 20-in casing inside the 30-in conductor. However, no case histories for dual casing exits at these large sizes were available. Potential problems included ability to mill the 20-in (0.5-in) and 30-in (1.0-in) casing wall thickness; potential mill tracking between the 20-in and 30-in casings; and the availability large milling bits. A unique solution was proposed: set two joints of 20-in casing in slips before running the whipstock; set a 16-in cased-hole WS using an expandable anchor just below the rotary table inside the 20-in casing; pull the entire assembly and hand-cut the window in the 20-in casing; run in hole with the whipstock inside the 20-in casing and cement in place; access and mill an exit through the 30-in conductor through the 20-in casing's precut window. A software program was utilized to ensure the correct alignment of the whipstock face to mitigate the risk of mill tracking.

In one trip, the whipstock system was safely run and successfully milled a window in the 30-in casing accessed through the exiting porthole in the 20-in string. The 16-in OD cased-hole whipstock lead and follow mills completed a 22ft long 17½-in exit in the 30-in casing. The exit was milled and dressed in just 11hrs during which 2000 lbs of steel accumulated at the ditch magnets. The minimum window gauge was 16 ¾-in, and the bottom of both windows was at 584ft. This effort marked the first time an exit was completed through 30-in casing. The whipstock assembly also drilled a 20ft rathole allowing the 16-in directional BHA to pass through the casing exit and drill ahead without issues or delay.
High Endurance Cutting Elements
Authors: Stowe Cal , Ponder Andrew
Published: June 2014

Unconventional oil and gas exploration has created ever-greater demands on milling technology as wells have gone deeper and the number of frac zones has increased. A new cutting element has been developed that can mill up to double the previous number of composite plugs or frac seats, allowing most wells to be milled in a single trip. The previous record for the most plugs drilled out with a single mill was 40. A mill dressed with these new elements removed 79 plugs in two different wells, and it holds the record for the most plugs removed from a single well after drilling out 52 in a single trip. Before this innovation, 30 frac seats were considered to be the limit in one trip. In the first five wells this element drilled 40 seats out of each well in a single trip.

Window mills with these elements have cut the first full-gage windows. Mills have been pulled with negligible diametral wear from a number of shale and limestone exits. This was achieved with multiple rows of cutting elements. The first row was damaged, but the additional rows were intact. The piéce de résistance occurred on March 20, 2013. The thickest casing in the world, used in massive salt formations that collapse ordinary casing, has challenged casing exit systems for decades. Exits out 7⅝-in. – 59 lb, 0.812–in. thick wall casing were cut in two trips with PDC mills; one trip to cut the window, and a second trip to fully open the hole and finish the rathole. The drilling bottomhole assembly (BHA) had long, large diameter directional elements, so a smooth, full diameter window was required. The mill dressed with the new cutting elements completed the exit and the rathole in the first trip. On the second trip, the assembly slid all the way to bottom without drag. One low cost carbide mill replaced two PDC mills.

Conventional mills typically leave thin steel flaps or sharp lips at the top and bottom of the window that can stick and/or damage the drilling assembly. Full scale rig tests have shown the new technology produces smooth edges at the top and bottom of the window.

The design of high-impact cutting elements required for many oilfield cutting applications is uniquely challenging. The elements must present an effective cutting edge regardless of orientation, have the same height whether standing or leaning, withstand substantial impact, have relatively low cost, and above all, have a long life to avoid a second trip.

Element design and case histories from frac plug, frac seat, casing exit, and drill pipe milling will be included for review and discussion.
The Use of Modeling to Enhance the Analysis of Formation Pressure Integrity Tests
Authors: Alberty M. W. , McLean M. R.
Published: June 2014

Formation pressure integrity tests (FPIT) are used to verify the integrity of cement at a casing shoe, measure the stress state of the exposed formations for well planning and operations, and determine the maximum equivalent circulating density (ECD) to which a shoe can be safely exposed. Critical decisions on operations are made directly from the results and include decisions about the need for remedial cement operations, maximum mud weights that can be used to drill the next well section, minimum mud weights that can be used to prevent hole collapse, calibration factors for predicting fracture gradients, and the potential need for lost circulation mitigation strategies.

The interpretation techniques of the result most frequently focus upon the point at which a fracture first initiates, the point where unstable fracture growth begins, or the closure pressure of the fracture when pumping ceases. However, the early pressure build-up behavior is often overlooked and can provide much insight on the integrity of cement, the point of initiation of a fracture, the permeability of the formation being tested, the need for cement remediation, and the potential to increase fracture resistance using wellbore strengthening techniques.

This paper presents a model for predicting early pressure build-up behavior, discusses how the model can be used to improve the interpretation of FPIT tests significantly, and provides examples of the application in select wells.
Defining and Improving Process Safety for Drilling and Well Services Operations
Authors: Chajai Hicham , Smith Clive
Published: June 2014

In 2007 Maersk Oil actively engaged in quantifying how Process Safety could effectively be implemented in drilling and well services operations. For years the term ‘Process Safety’ had been effectively embedded and understood in our production operations, whereas it was lesser known in the drilling community, where ‘well control’, ‘barrier philosophy’ and ‘Safety First’ were the phrases heard on the rigs.

Initial efforts were exerted in order to establish the right framework and terms of reference that would be suitable for drilling and well services. Likewise it was important to establish a baseline in terms of effectiveness of its management of Process Safety. Thus, the Company looked to create relevant tools in order to qualitatively measure its performance and enable continuous improvement.

The objective of this paper is to present a case story, as to how the broad definition of Process Safety has been successfully implemented within the drilling and well services discipline and how we are able to measure effective embedment as well as continuous improvement.

The Company adopted the Risk Based Process Safety (RBPS) (based on 4 main ‘pillars’ and 20 key elements) approach, originally developed by the petrochemical industry, but now also a recognized approach in the oil industry, to ensure effective management of Process safety.

This paper describes the development of a questionnaire, now available as a web-based self-assessment tool that evaluates and measures the maturity of Process Safety understanding, commitment and implementation across locations and also across disciplines. It also describes how the assessment is being used for continuous improvement and management review.

As part of the process, a discipline specific information booklet and a tailored training program were developed and rolled out to all drilling & well services technical personnel, thus providing enhanced knowledge and understanding of the principles of Process Safety.

This paper describes the methodology employed to select Global KPIs.

Finally, the paper will explain how the management system is already applying Process Safety, thus supporting Company's ambition of an "Incident-Free" operation.
Complex Wells: New Perspective on the Selection of Optimal Drillpipe
Authors: Mehrabi Mehran , Miska Stefan , Merlo Antonino
Published: June 2014

Drilling of extended reach wells (ERW) and ultra-deep HPHT wells is the most compelling reason for drilling companies to look for alternative drill pipes that meet their requirements. Currently, with the emergence of drill pipes made of materials other than steel, a thorough study of their advantages and disadvantages compared with conventional drill pipes is needed. In this study the main focus is on the comparison of fatigue performance of Steel Drillpipe (SDP), Aluminum Drillpipe (ADP), and Titanium Drillpipe (TDP) in mild and severe doglegs. Fatigue performances of different drillpipes are compared and it is shown that depending on the drillpipe specification, applied torque, axial load and Dogleg Severity (DLS) of the wellbore, one type can function better than others and a one-size-fits-all is not an appropriate approach on the selection of drillpipe material. Generated contact forces at the tool-joints and pipe body adds more complexity to the decision of which type of drillpipe is more appropriate for drilling a severe dogleg. The contact forces at the tool-joints and pipe body could be an extremely important factor owing to their direct impact on wellbore stability, casing and pipe body wear and the heat checking of the tool-joints. Large contact forces at the pipe body can make relatively major scratches on the surface of the pipe tube of ADP and TDP, which can render their corrosion resistance features insignificant. Based on the conducted study, TDP has a significantly good fatigue resistance even at the simultaneous presence of high applied torque and axial load, and severe doglegs, which makes the use of other options (SDP and ADP) impractical from the fatigue failure standpoint. It is shown that the limiting factor for using TDP in such severe conditions is not the fatigue resistance of the material that the pipe is made of, but the high contact forces between the wellbore/casing wall and tool-joints/pipe-tube. The fatigue envelopes and calculated contact forces for each category of drillpipe reveal the practical range of the applied torque and axial load, to avoid both suffering from fatigue failure as well as detrimental effects to the wellbore integrity. This paper can help drilling engineers design an optimal drillstring for ERD and complex wells.
Successful Cementing Based on New Design Methodology for Displacement of Non-aqueous Drilling Fluid
Authors: Kefi Slaheddine , Pershikova Elena , Docherty Kevin , Barral Quentin , Droger Nicolas , de la Mothe Loic Regnault , Khalfallah Inès
Published: June 2014

Drilling fluid removal by spacer fluids is an important step in ensuring proper cementing and therefore adequate zonal isolation, especially when non-aqueous fluids (NAF) are used. In addition to the fluid mechanics aspect of displacement, a tensioactive package containing surfactant(s) and solvent(s) is typically added to the spacer base fluid to clean all surfaces, including the casing. However, current surfactants and solvents on the market have limited application in terms of temperature and type of drilling fluids.

API and ISO standards recommend practices for evaluating the suitability of a spacer. The viscosity of NAF, spacer, and cement mixtures at various fixed ratios determines their rheological compatibility. The reverse-emulsion test or spacer-surfactant screening test (SSST) determines the percentage of spacer for inverting the NAF emulsion. Other non-standardized tests such as bottle tests or grid tests determine the efficiency of a surfactant/solvent aqueous solution to remove NAF from metallic or glass surfaces. But all these tests suffer from lack of reproducibility and limited automation.

Improved alternative laboratory procedures have already been proposed. They include measuring rheology during SSST, which clearly shows the positive impact of early emulsion inversion on viscosity of NAF/spacer mixtures. In addition, proper preparation of metal surfaces clearly improves repeatability of the cleaning test, which now is performed with weighted spacer under temperature and pressure.

Using these improved experimental methods, we performed more than 3,000 different tests on more than 200 tensioactive blends. Statistical analysis helped in selecting the optimum chemistry as a function of the conditions (type of base oil, salinity, and temperature). This allowed developing both guidelines and a tensioactive package comprising a limited number of chemicals (surfactants and solvents), from which the field user would select the ones to combine for the application. Only a few confirmation tests would be necessary at the location for planning a given cement operation.

An advantage of developing a package of chemicals is ease of implementation at field level since it requires having only a few chemicals in inventory to cover all situations and limited local laboratory testing. The new methods have been successfully applied in several wells in which different types of nonaqueous fluids were used at various temperatures.
Improved Model for Tapered Casing Design under Pressure Testing
Authors: Samuel Robello , Wang Zhenying , Kumar Aniket , Gonzales Adolfo
Published: June 2014

The casing program constitutes a significant portion of total well costs and thus calls for an efficient and accurate casing design. One aspect that is very important is accurately calculating the service load in a tapered casing string. Estimating the load when conducting pressure tests in tapered casing in a deviated well is very complex. In addition to the ballooning force, the piston forces acting on cement plugs and cross-sections at casing size changes result in 3D forces. When both the casing hanger and casing shoe are fixed, the casing string becomes a statically complicated indeterminate mechanical system. Thus, the service load distribution in tapered casing in a deviated well is very different from the load distribution in a vertical well or in a single section casing design. Underestimation of the load creates inherent safety issues.

This paper presents a new mathematical model to solve the load for a constrained casing system in a deviated or vertical well, using the Transfer Matrix Method (TMM). The distribution of forces along a tapered casing string in a deviated well are accurately calculated and presented in this paper. Example calculations are presented with details. Calculation results show that the distribution of the service load is greatly affected by the well trajectory, location of cementing plugs, the selection of casing, etc.
The Operational Benefit of Testing HPHT/MPD Procedures Using an Advanced Full Scale Drilling Simulator
Authors: Blikra Harald , Pia Giancarlo , Wessel Just Sverre , Svendsen Morten , Rommetveit Rolv , Ødegård Sven Inge
Published: June 2014

A challenging HPHT well was drilled with Managed Pressure Drilling. In the preparation phase, an advanced dynamic drilling simulator was used by the operator in order to test and verify operational procedures as well as the HPHT & MPD well control manual. This drilling simulator is based on advanced dynamic models developed from first principles, and will respond very realistically on the operators actions when "drilling", "circulating", "managing the well control problems" etc; like a "Drilling Flight Simulator". All relevant HPHT effects are modeled, like mud density, compressibility and rheology as function of Pressure and temperature; gas solubility in Oil Based Muds, transient thermal interaction in the well and surroundings etc. An MPD module has been developed in the simulator, allowing testing and training of all relevant procedures and operations related to MPD. Also, the drilling rig characteristics (pumps, surface lines, choke and BOP, MPD toolkit etc.) are modeled according to the real rig specifications.

The testing lead to several significant changes to the operator's manual and operational procedures. At the same time it allowed the Engineering team to test and rectify the Drilling program prior to deployment of the operation. The MPD technique was tested in the simulator as well, and the various contingency procedures were assessed. It allowed the rig contractor, operator, and the MPD provider to find the operational routine, communication and best practice prior to start operation offshore. The team's decision trees where reviewed and updated during the simulator training.

Since the crews actively had a part in the final revision in the manual, the operator experienced that the crews took an ownership in the making of the manual and the offshore operation.

As a resultant effect, the drilling crew and MPD operators rapidly adapted to the MPD procedures agreed upon during training, when operation started.

This paper will briefly present the advanced drilling simulator, and focus on the testing and verification of procedures and well control manual. The modifications done will be presented, and the operation itself will also be described, highlighting the benefits of utilizing the drilling simulator prior to operation.
Temporary Severe Reduction in Drill Pipe Load Capacity Due to Frictional Heating
Authors: Desrosiers Andrew , Marchman Kellon , Gokhale Samit
Published: June 2014

Numerous cases of drill pipe overload failures have occurred while rotating and reciprocating the drill string under packed off conditions where circulation is either low or lost completely. These failures are typically known as "down-hole heating" failures. The failure mechanism and forensic evidence needed for identification of the failure mode has been presented in a technical paper (SPE/IADC 92429). This failure mechanism occurs when frictional heating, along with poor or no circulation of drilling fluid results in extremely high localized temperatures in the tube. Material temperatures above the steel's austenitic transformation temperature can be reached causing a microstructural transformation and alteration of the material properties. However, when the material temperatures do not exceed the austenitic transformation temperature, the microstructure does not change but the mechanical properties can be drastically altered temporarily, leading to an overload failure. The understanding of failures occurring under this scenario and the supporting forensic evidence is still in the developing stages due to a lack of empirical data.

This paper provides multiple case studies where packed hole conditions with lost circulation were present and drill pipe tubes failed from overload deep in the well with low tensile loads relative to the rated tensile capacity which is consistent with "down-hole heating" overload. In these cases, the failure samples did not provide the physical evidence and microstructural transformation signatures described in the previous work paper SPE/IADC 92429. It was postulated that the failure occurred due to frictional heating but the material temperature did not reach austenitic transformation temperatures required to change the material microstructure. The paper presents experimental data that demonstrates the effect of elevated temperature on material strength for S-135 drill pipe tube materials at temperatures ranging from room temperature to austenitic transformation temperatures. Two separate tensile tests were conducted for each temperature throughout the range: one set of tests were pulled while the samples were at the elevated target temperature, the other set of tests were pulled after the samples had air cooled to room temperature from the target temperature.

The experimental data obtained in this study documents that the yield strength of S-135 drill pipe tubes can be temporarily reduced up to approximately 90% when heated to elevated temperatures below the austenitic transformation temperature with no change of material microstructure. The data provided in this paper provides the industry with valuable information when evaluating down-hole heating failures.
Drilling with Production Liner reduces AFEs per well, brings to early production in Urmanskoye field onshore Russia
Authors: Sidorenko Kirill , Valiyev Gurban , Priymachenko Dmitry , Beattie Scott , Bakhtin Andrey , Dubovsev A. G
Published: June 2014

As an industry segment, drilling with casing and liner is still very much in its infancy. However, a few "early adopters" have been successfully extending the operational envelope and discovering new applications. The fundamental value of drilling with casing lies in improving drilling efficiency by eliminating flat spots in the drilling curve. It also has the capability of extending open hole sections to reach deeper casing points with smaller diameters, thus eliminating contingency intermediate strings. The implications for exploration and production industry are significant. Currently, there are two basic methods of drilling with casing divided as follows: Rotating the casing at surface to transmit torque to the drilling BHA, or having a retrievable BHA latched inside the casing that incorporates a motor that drives a conventional bit and underreamer. Both systems, though operational and technically sound, still have many technical issues to overcome concerning all aspects of well planning to operations on the rig floor. This paper will focus on drilling with liner by rotating the casing without Top Drive. The paper will highlight the significant lessons learned from these experiences. This emerging technology is considered ‘"game-changing" and is seen as complementing the expandable and underbalanced technologies which promise to revolutionize well construction.
Selecting Safe Mud Weight Window for Wellbore in Shale While Drilling Using Numerical Simulation
Authors: Han Yanhui , Meng Fanhong (Frank)
Published: June 2014

In conventional drilling, the lower bound of the safe mud weight window is usually chosen for preventing compressive shear yielding evaluated by applying various failure criteria, such as the Mohr-Coulomb criterion on the elastic stresses, while the upper bound is typically determined by the fracture initiation pressure. For the wellbore drilled in shale formation, however, the lower bound calculated using a conventional method becomes unsafe because of the complications introduced by various shale issues, such as bedding planes. In this paper, two approaches are used for computing the safe mud weight window for wellbore drilled in shale formations. In the first approach, the effect of bedding planes is absorbed in the equivalent rock strength properties in the theoretical analysis. The second approach involves performing direct numerical simulation with bedding planes modeled explicitly in the constitutive model. A case study indicates that the two approaches provide consistent results.
Analysis of Spiraled Borehole Data using a Novel Directional Drilling Model
Authors: Marck J. , Detournay E. , Kuesters A. , Wingate J.
Published: June 2014

This paper describes the application of a directional drilling model to wellbore spiraling and compares it to field data. In this paper, the spiraling tendency of a Bottom Hole Assembly (BHA) is determined from a stability analysis of the delay differential equations that govern the propagation of a borehole. These propagation equations are derived from a novel mathematical model, constructed by combining (1) a bit/rock interaction law, which relates the forces acting on the bit to the penetrations of the bit in the rock per revolution; (2) kinematical relationships, which link the bit motion to the local borehole geometry; and (3) a model for the BHA, which expresses the forces and moments at the bit from the external loads and the deflections imposed by the stabilizers. Spatial delays associated with the positions of the stabilizers account for the feedback of the borehole as the stabilizers interact with the wellbore.

The analytical form of the propagation equations makes it possible to carry out a stability analysis and determine whether borehole spiraling is expected. The coefficients of the propagation equations embody the characteristics of a particular drilling system; these include the BHA configuration, bit properties, and the active weight, Wa, a calculated reduced weight on bit that depends on the actual Weight On Bit (WOB), the cutter wearflats, and the rock strength. If the bit trajectory is unstable, then any perturbation in the borehole geometry is amplified gradually, eventually leading to the generation of a spiraled hole.

The stability of the bit trajectory essentially is controlled by the magnitude of a dimensionless group relative to a critical value that depends on the BHA configuration. This group is a function of the lateral steering resistance of the bit, the bit wear, the rock strength, and the WOB. Thus, a BHA can be either stable or unstable depending on the selected bit, its state of wear, and the WOB.

Predictions of the stability analysis are compared with field data from spiral holes pertaining to eight sections from four wells drilled with different bit types and BHA configurations. The paper shows that the propensity of a BHA to spiral can be predicted by the model by assuming reasonable values for parameters such as the lateral steering resistance and the part of the WOB transmitted by the cutter wearflats. This comparison suggests that the model can be used to optimize BHA designs and critical WOB levels that will mitigate the creation of spiral holes.