bluuebunny/crossref_metadata_2025 huggingface dataset:
Case History of a Challenging Thin Oil Column Extended Reach Drilling (ERD) Development at Sakhalin
Authors: Gupta Vishwas P. , Sanford Shea R. , Mathis Randall S. , DiPippo Erin K. , Egan Michael J.
Published: March 2013

ExxonMobil, as operator for the Sakhalin-1 project, recently planned a drilling campaign at the Chayvo Field, Sakhalin Island, Russia. The focus of this campaign is the development of a thin oil column reservoir using extended reach drilling (ERD). This paper will provide an overview of the planning of these challenging wells at the edge of the ERD envelope, the associated technical and operational challenges, and the additional complexity of targeting a thin oil column in an ERD environment. Significant well design parameters, tools, and techniques to enable these challenging wells will be presented. Results to date from this drilling campaign will also be presented.

ERD has become a commonly used technique to economically access reserves from existing infrastructure and to reduce the facilities environmental footprint. The case history described in this paper illustrates the combination of planning, technical design, and operational practices required to push the ERD envelope further.

The distance of the reservoir from shore resulted in planned well lengths at the edge of the ERD envelope. Planning of these record wells involved building upon the Operator's previous experience as well as additional tools and methods to address the unique challenges. The technical challenges included uncertainties in the location of the oil column and fluid contacts, very accurate well placement for effective reservoir drainage and preventing early gas/water breakthrough, completing long horizontal intervals, and high torque and drag. The geologic uncertainties and wellbore positioning challenges were addressed using a combination of a single near horizontal pilot hole to locate both fluid contacts and a novel technique to minimize vertical position uncertainty using formation pressure measurements while drilling. Extensive torque and drag and wellbore stability modeling were performed to design the wells, operational parameters, and equipment. Completion designs were optimized to ensure successful placement in long horizontal intervals.
Dual Fuel progress in reliability and performance for the Oil and Gas market
Authors: HENIN Eric
Published: March 2013

A diesel engine fitted with an aftermarket add-on gas fuel system that provides a supplemental fuel source is generally called a Dual-Fuel system. Dual-Fuel usage can lower fuel costs by as much as 70 percent, as compared to a standard diesel engine. While functional, these systems can create challenges for emissions and engine longevity.

In 2013, a leading engine manufacturer will be offering Dynamic Gas Blendings, a comprehensive Dual-Fuel solution for land drilling and land production gensets, as well as well fracturing application engines.

With average crude oil prices almost doubling from 2009 to 2012, oil and gas producers using traditional diesel powered drilling rigs have seen rising operating costs. Additionally, further government regulations on emissions and wellhead gas flaring are putting increased pressure on oil and gas producers to prioritize sustainability initiatives. In some cases, these regulations mandate the use of associated gas produced with crude oil production, much of which is currently flared today.

Oil and gas producers who use the Dynamic Gas Blending solution, as compared with standard Dual-Fuel, will benefit from:

▪ Reduced flaring. ▪ Unique safety features. ▪ Diesel and gas engine controls interconnected for automatically optimized performance. ▪ Simplified operations, with no re-adjustment necessary. ▪ Simplified operations, with no re-adjustment necessary. ▪ Improved emissions, with possibilities of certification for the genset. ▪ Extended run times from existing diesel tanks. ▪ Greater fuel flexibility, with a good tolerance of associated (flare) gases. ▪ Generator sets and gas blending systems manufactured specifically for harsh oil and gas environments.

Dual-Fuel and Dynamic Gas Blending are technologies that allow oil and gas producers to manage operating costs while being environmentally responsible. Because gas is a significantly lower-cost fuel compared to diesel and is clean-burning, they allow oil and gas producers to save money and reduce their environmental impact.
Successful Application of Concentric Casing Nitrogen Injection to Overcome Drilling Challenges and Deliver a Record Horizontal Well in the Tecominoacan Field
Authors: Rodriguez Reginaldo , Franco Roberto , Gamez Gustavo , Blas Bernardo , Gonzalez Fernando Daniel , Vasquez Jose Luis , Alcudia Hugo
Published: March 2013

The Jujo-Tecominoacan field belongs to the Bellota Integral Active in the Pemex South Region. It is located in the state of Tabasco, northwest of the city of Villahermosa. This field is geologically located in the Chiapas-Tabasco Mesozoic Basin and is developed to maximize production of fractured carbonate formations from the lower Cretaceous to the Kimmeridgian Jurassic. Several drilling challenges are presented including horizontal drilling in dolomites with a high compressive strength, low pressure and high temperature reservoir requiring the use of a biphasic drilling fluid with nitrogen injection through concentric casing annular space, crossing through Cenozoic members of abnormally high pressure that require managed pressure drilling, drilling through inverse geologic faults, and proximity to a salt dome.

An interdisciplinary team was formed between the service company and operator to meet the challenges of constructing the deepest and longest concentric N2 injection horizontal well in the world with a total depth of 6611 m in a Low Pressure-High Temperature ambient. A horizontal production section was drilled to a length of 862 m and with an average inclination of 84°. The main objective was to maximize production in fractured carbonate formations from the lower Cretaceous to the Kimmeridgian Jurassic formation. Managed pressure drilling was implemented in the 6 ½" hole section while drilling through the upper Jurassic production zone, allowing establishment of commercial production and incorporation of the oil reserves in these zones.

With 260 days of operation, the Tecominoacan 705 well, is the pioneer example of a combined effort of the operator and service company with the objective accomplished, setting a worldwide standard of unprecedented execution.
The Application of Advanced Gas Extraction and Analysis System Complements Early Kick Detection & Control Capabilities of Managed Pressure Drilling system with added HSE value
Authors: Patel Bhavin , Cooper Todd , Billings Will
Published: March 2013

Managed Pressure Drilling (MPD) has gained industry-wide acceptance as a technology that enables drilling into the challenging zones. Narrow pore pressure - fracture pressure window, depleted reservoir zones, highly fractured reservoirs and deep-water wells are few examples of such challenges. Weatherford's MPD system has proved its effective application in drilling challenging wells. Its unique early kick and loss detection software capability helps to identify such event in very early stage, take corrective action and hence to minimize the nonproductive time. Early detection of a kick / loss event helps in minimizing the potential risk posed by the event and ensure safety during the operations.

Weatherford's advanced gas extraction and analysis system uses an innovative membrane technology and high speed gas chromatograph to improve surface gas detection and analysis in real time. This capability was utilized in conjunction with accurate flow metering capability of MPD system. Various tests were carried out to validate the advanced gas detection system's capability to detect and analyze gas in mud. During circulation of the influx, data from gas detection system helped to plan the strategy gas on the surface. The test data was validated by the data from real wells.

Feedback from the advanced gas detection system also helped to control the break out of the dissolved gas from oil based mud by varying surface back pressure through automated chokes. This is very critical to ensure that gases containing hydrocarbons are handled safely on the surface. It also provided quantitative analysis of the lighter and hence volatile hydrocarbon components. Circulation rates and surface back pressure can be used to mitigate potential hazards. Use of advanced gas extraction system in combination with MPD system added significant HSE value by making well control operations more efficient and safer.
Subsea Cap & Contain Method for a Deepwater Tension Leg Platform
Authors: Henley John A. , Webb Tammy , Wibner Chris , Soliah James
Published: March 2013

A tremendous amount of effort has been placed on subsea cap and containment in order to demonstrate the exploration and production industry's response to a subsea well control event. This paper will focus on the methods and processes planned to contain a subsea blow out beneath a Tension Leg Platform (TLP) in deepwater Gulf of Mexico. Response to a well control event of this type is divided into 3 major categories: 1) TLP Health and Stability Monitoring - Understanding the structure stability is key in planning the response and determining the time allowed to deploy containment assets, 2) Debris Clearing-a path must be cleared into the well pattern horizontally and vertically for the capping stack to be deployed and 3) Stack Deployment - with the TLP still floating above the well pattern the stack must be deployed laterally under the facility and onto the well. Several challenges were encountered during the design and approval of this containment method, leading to the development of alternative capping strategies, purpose built capping stacks, installation of permanent monitoring / response equipment and use of Delmar's Heave Compensated Landing System (HCLS) to accomplish these critical subsea tasks.
High Performance Water-Based Drilling Fluids - An Environmentally Friendly Fluid System Achieving Superior Shale Stabilization While Meeting Discharge Requirement Offshore Cameroon
Authors: Witthayapanyanon Anuradee , Leleux Jerome , Vuillemet Julien , Morvan Ronan , Pomian Andre , Denax Alain , Bland Ronald
Published: March 2013

Historically, invert-emulsion drilling fluids are the system-of-choice for drilling offshore Cameroon due to minimum NPT, high ROPs, ease of maintenance, robust performance under various downhole conditions, and the resulting lower drilling costs. However, with a regulatory environment moving toward zero discharge, the cost of the waste management associated with invert-emulsion drilling fluids is diminishing their attractiveness. Therefore, when the operator was planning to drill their next development well offshore Cameroon (BaF field, Douala Basin), they evaluated high-performance water-based mud system (HPWBM) alternatives. HPWBM systems offer the potential advantage of offshore discharge of drilled cuttings and effluents due to absence of oil contamination and lowered waste management costs.

This paper documents the advantages of the selected HPWBM, and its design and performance characteristics in stabilizing reactive clays/shale. Specially designed chemical components in the HPWBM formulation created an efficient osmotic membrane, thereby minimizing pore pressure transmission under downhole conditions. This HPWBM system is one of the first commercial applications of nanotechnology in drilling fluids. The field recap demonstrated that the selected high performance water-based drilling fluid met expectations by achieving the required drilling performance and high shale stabilization with zero environmental impact. Finally, the paper reviews the cost reduction in waste management when switching to the environmentally friendly high performance water-based mud system.
Drilling Fluid Selection Methodology for Environmentally Sensitive Areas
Authors: Burden Paul , Dimitriadis Klisthenis , Clements Kayli , Nguyen Chau , Staples Tony , Thomas Seye
Published: March 2013

When operating in areas of Africa which are particularly sensitive environmentally selection of drilling fluids should take into account both technical and environmental criteria in regards to the treatment and disposal of the cuttings and excess fluids. In this particular case the operator's choice of drilling fluid during its exploration and appraisal campaign was driven primarily by the need to use fluids with green credentials, and the fact that the exploration wells were not particularly demanding from a technical point of view. However, it was recognised that a system with improved technical performance woud be required when drilling the anticipated, more demanding, high angle and extended reach wells during the development drilling. When enough core and drill cuttings became available a thorough study was performed which comprised shale characterisation and inhibition testing. Seven drilling fluid compositions were tested, six water based and one synthetic based. A simple rating method was devised for ranking technical and environmental performance as well as treatment and disposal options for each fluid. The synthetic based mud was the strongest technically followed by an amine-modified high-performance water based system. It was shown that both can be combined with techno-economically feasible treatment and disposal options that minimise environmental impact.
On the Shear Degradation of Lost Circulation Materials
Authors: Valsecchi Pietro
Published: March 2013

The introduction of large size materials in the drilling mud circuit has become a common practice over the past few decades for the mitigation of Lost Circulation while drilling in permeable intervals. Solids with an average diameter larger than 100 pm are carried with the drilling mud and, when fractures occur, they deposit at the opening of the fractures, successfully blocking the discharge of fluid out of the wellbore. The effectiveness of such material has been observed, however, to decline over time as the drilling mud circulates through the mud pumps, the drill string, the bit nozzles, the wellbore annulus, and the mud recycling system. The decline over time in the effectiveness of Lost Circulation Materials (LCM) and Loss Prevention Materials (LPM) during drilling is widely linked to the degradation of the LCM/LPM components whose average size drops with circulation time.

A large amount of literature in the petroleum industry is dedicated to the investigation of the issue and numerous experimental studies have attempted to quantify the LCM degradation by reproducing the root phenomena in laboratory. The concept of "shear degradation" has thus become a synonym for such studies and it is widely used for the selection of materials to be used in drilling operations.

In the present paper, a harder look is taken on the very concept of "shear degradation" and on its effectiveness in capturing the progressive size reduction of LCM/LPM during circulation. Using dimensional analysis, the tendency of a material to degrade can be determined in advance, whereby the density of the particles and suspending fluid, the size of particles, and the fluid viscosity are examined as the governing parameters. Understanding the underlying physics enables the selection of a more shear-resistant engineered-particle drilling fluid, regardless of its application.
Numerical and Analytical Investigation of Smear Effect in Casing Drilling Technology: Implications for Enhancing Wellbore Integrity and Hole Cleaning
Authors: Salehi S. , Mgboji J. , Aladasani A. , Wang S.
Published: March 2013

The "Smear Effect" during Casing Drilling can help to increase the fracture gradient, mitigate lost circulation problem and reduce Non Productive Time (NPT) in drilling operations specifically narrow pore-fracture pressure sedimentary basins and deep offshore applications. This is due to plastering of cuttings to the wellbore wall which may enhance wellbore hoop stress by wedging created fractures or increase fracture propagation pressure. Although some field applications have increased wellbore integrity, uncertainties remain regarding the mechanisms by which this occurs and how to operationally capture the maximum attainable wellbore pressure. More importantly, the "Smear Effect" has never been quantified scientifically. The uncertainties include the optimum ratio of the casing to the open hole size, casing rotation, contact between the casing and the mud cake, type of drilling fluid, casing eccentricity and the fluid's hydraulic complexities. This paper provides new insights on "Smear Effect" by presenting numerical and analytical models to to clarify and optimize relevant parameters in casing drilling applications. Advanced finite-element methods were used to model the near wellbore area under considerations of various pipe/open hole ratios and mud-cake contacts in each simulation. The models consider geomechanical properties in both the mud cake and formation. Actual operational data from one of the fields in South Texas was used for simulations. Analytical models were also used to calculate the contact force for each set of casing sizes and rotations. The force then used as the new boundary conditions in finite-element models and mud cake failure was evaluated.

The results indicate that casing rotations up to 100 rpm cannot result in mud cake failure; however, this cannot be confirmed firmly due to uncertainties regarding mud cake properties. In addition, increasing the casing ratio will reduce the risk of mud-cake failure when increasing casing rotations. Hydraulic calculations show a sharp increase in the bottom-hole pressure when the casing-annulus size ratio exceeds 0.8 in concentric situations.
Advances in Real-Time Event Detection While Drilling
Authors: Wong R. , Liu Q. , Ringer M. , Dunlop J. , Luppens C. , Yu H. , Chapman C.
Published: March 2013

Accurate, quick, and reliable event detection is essential to both conventional and automated drilling processes. Methods for real-time detection of events using Bayesian inference have been described previously. These systems were initially designed to provide alarms to rig crews with little or no operator setup or maintenance. These requirements have resulted in certain limitations that restrict their use to relatively simple situations. For example, the drillstring washout detection method was based primarily on the behavior of hydraulic coefficients of a simple hydraulic model computed from standpipe pressure and flow, which meant that it was limited to only scenarios of drilling without a mud motor. New sensors and enhancements to the Bayesian inference techniques significantly improve event detection.

Although applicable to a broader set of events, improvements to these detection methods can be explained using the example of a new drillstring washout detection module. The new module combines a method of detection of on-bottom drilling with enhanced signal characterization of standpipe pressure and flow to create an algorithm that can effectively handle drilling with a motor. Another improvement in the washout detection algorithm is the use of MWD turbine RPM when it is available. Unaffected by the differential pressure and depth changes, the turbine RPM data have proven to be more effective in detecting washouts occurring in the drillstring above the MWD tool.

Testing both on data from several previously recorded washouts in drillstrings and on real-time data from wells with washout demonstrates the new capability of the algorithm to detect these difficult-to-characterize events while keeping false detections to a minimum.
Downhole Vibration Analysis: Fishing Agitation Tool Efficiency in Stuck Pipe Recovery
Authors: Voghell Mark , Mohanna Assaad , Hanley Christopher , Al-Khiriseh Cristinel , Al-Mousa Ahmed , Al-Amri Ali
Published: March 2013

A challenging and costly situation to overcome in modem day directional drilling applications is stuck pipe in open hole due to differential and/or mechanical sticking forces. Chances of recovery decay with time and conventional fishing with a bottomhole assembly (BHA) is frequently unsuccessful. By incorporating downhole axial-oscillation technology, the fishing reliability and effectiveness improve exponentially. The Fishing Agitation Tool (FAT) is an excitation component of the fishing BHA used to deliver low impact, high energy oscillation to the engaged fish. The FAT keeps the string in motion, breaking static sticking friction.

The FAT was used in Saudi Arabia for the first time to recover differentially stuck BHAs from a 6 1/8 in. hole in deep, high angle wells. The initial application involved pipe that was stuck in hole for more than 12 days without any movement, during which several conventional fishing BHAs failed. FAT was run in the final fishing BHA, getting the fish free after an hour of axially agitating and stroking the fish. After the pilot field trials in Saudi Arabia, and several successes in recovering mechanical and differential stuck BHAs, downhole vibration analysis proved the FAT effectiveness in assisting fishing BHAs in recovering stuck pipe more efficiently.

The FAT offers a new level of fishing technology that maximizes the effect and reliability of fishing BHAs in challenging wellbore environments, where conventional fishing techniques are deemed insufficient. This increased efficiency offers substantial reduction in fishing lost time, and an increased potential for fish and well recovery.

This paper investigates the effectiveness of the Fishing Agitation Tool through a study of the impact forces, impulse and drag forces generated by the FAT compared to conventional jarring operations, utilizing drag modeling as well as jarring analysis software.

Successful cases histories are reviewed to highlight the benefit of this technology.
Safely Exceeding Buckling Loads in Long Horizontal Wells: Case Study in Shale Plays
Authors: Menand S. , Chen D. C-K
Published: March 2013

Drilling operations face several limits that intensify uncertainty and risks. Due to the deeper or/and longer wells, drilling equipment is pushed to its mechanical and endurance limits. The general industry perception is that when drill strings or casing strings exceeding conventional helical buckling criteria, they cannot be operated safely in the hole as the risk of failure or lock-up is too high. However, some theoretical, experimental, and field case studies have shown that tubular may be run in the hole even in a buckling state, within safe limits. This paper shows a case study in long horizontal wells for which helical buckling load has been exceeded without compromising the success of the operations.

Drilling data from Bakken field in North Dakota have been gathered, analyzed and compared to an advanced drill string mechanics model that enables simultaneous calculation of torque, drag, and buckling. A strong focus has been placed on the comparison between conventional buckling criteria and drill pipe or tubular bending stresses. Field results supported by drill string modeling suggest that the helical buckling load has been exceeded during operation at some locations along the drill string during slide drilling and liner running but with bending stresses at an acceptable level. However, in rotary drilling, buckling should be avoided because it will create high vibrations. In this case study, the effect of drill string dynamics is not considered.
Dust Collection System for Personnel Health During Fracturing Operations
Authors: Anderson T. , Hooker C. , Uttecht A. , Boucher M. , Wagner N.
Published: March 2013

Use of silica sand as a proppant has grown dramatically over the last decade with the rise in production of unconventional resources. Massive volumes of sand are transported to a wellsite and pneumatically conveyed into frac sanders. After formation fracture, sand is moved from the sanders across conveyers into the blender where it's mixed with fluid for transport downhole. During these operations, a significant amount of silica dust enters the air and onsite personnel are exposed. The dangers of inhaling dust and fine particles have been known for hundreds of years, yet many workers today are still not adequately protected. Silicosis, the most widespread industrial disease, results from exposure to crystalline silica and kills hundreds of workers every year and detrimentally affects the lives of untold more. Historically, many cases of silicosis have been associated with sand blasting, mining, and construction. There is now potential for connections to the hydraulic fracturing industry. Symptoms of silicosis can take 10-15 years to materialize, but once it develops the disease progresses incurably. According to a recent U.S. National Institute for Occupational Safety and Health (NIOSH) study, many frac sites exposure levels exceed, sometimes by a factor of 10, the NIOSH Recommended Exposure Limit (REL) to crystalline silica.

The rapid expansion of the hydraulic fracturing industry has in some places outpaced necessary regulations and equipment for worker safety, especially dust control. A dust collection system has been developed to target sand filling operations where sand particles are likely to be released into the air. With a system in place that aims to contribute to the U.S Occupational Safety and Health Administration (OSHA) permissible exposure levels (PELs), the threat of silicosis is significantly reduced from the hydraulic fracture process and unconventional development is made safer for everyone involved. This paper will discuss the dust collection equipment, its deployment and integration with existing equipment, as well as other activities to reduce worker exposure.
Innovative Drilling System with a Built-in Kick-off Ramp Allows Dependable Curve Building in Granite Wash Formation
Authors: Bruton G. A. , Talkington J. , Desai P. , Swadi S. , Kelley J.
Published: March 2013

The Granite Wash formation in Beckham County, Oklahoma and surrounding areas presents a number of unique challenges in drilling the build section from a vertical openhole to form a horizontal lateral in the productive zone. The formation is hard and abrasive and it is difficult to anticipate rock properties downhole from one well to the next. The erratic nature of the formation results in unpredictable performance by the steerable drilling assembly and drill bits particularly in the build section below 12,000 ft. In most cases, the target build rates are not achieved forcing multiple trips and undesirable cost overruns.

To remedy the issue, an innovative drilling system was developed which provides a dependable kick-off ramp and a firm beginning in initiating the build section without having to rely on the drilling BHA's fulcrum point. From the bottom, the drilling system consists of hydraulically set openhole anchor, a whipstock, an impregnated drill bit mechanically attached to the top of the whipstock, a double bend turbodrill section and the rest of the BHA. The procedure includes positioning the drilling system in the hole at kick-off point, orienting the whipstock face with MWD in a desired direction, anchoring the whipstock by hydraulically setting the anchor, disengaging the BHA from the whipstock and commencing drilling operations. All of these steps take place in a single trip downhole. Once the impregnated bit and the turbine assembly pass the whipstock, the sliding and the rotating phase begins to achieve the target build rate.

The authors will describe the system's components and the running procedure. They will also discuss system performance, realized benefits to the operator, lesson learned and planned improvements going forward.
The Stability of a Pipe Stand Racked in a Derrick, Part 2 - A General Pipe Stand Model
Authors: Sawaryn S. J , Pattillo P. D
Published: March 2013

This paper builds on the information contained in part 1 and presents a general pipe-stand model. The model is based on the Fourier series solution of the energy equation for calculating the deflection and buckling condition of an inclined, non-uniform pipe stand with an arbitrary number of intermediate loads and stick-up above the top racking board. Full details of the derivation and algorithms are included in the paper. This flexible approach is used to examine more complex, practical situations including the buckling sensitivity to the position of the upper support and added loads such as tool joints or running tools racked with the stand.

Using a Fourier sine series solution avoids dealing with the less familiar higher order functions encountered in part 1 so that the algorithms can be coded using standard spreadsheet functions. This approach also increases the model's capability and practical worth, providing a tool suitable for field use. The results for loaded, uniform stands compare within 0.01% with the limiting cases represented by the analytical solutions presented in Part 1. Non-uniformity of the stand can add significantly to the number of series terms required.

Several practical examples are used to illustrate the model's application, including the analysis of stand with a heavy intermediate load where buckling occurred. The model successfully distinguishes between the buckled and non-buckled conditions.
Anatomy of MPD Well Failures: Lessons Learned from a Series of Difficult Wells
Authors: Dow B. , Baker J. , Spriggs P. , Voshall A.
Published: March 2013

Managed pressure drilling is a technique viewed as a means of improving the chances to drill the most challenging wells. Wellbore pressure management allows operators to address key technical risks such as narrow pore pressure and fracture gradient windows, sensitive wellbore stability environments and navigating steep and unknown pore pressure ramps. Certainly, the technology delivers added advantages while the drilling team attempts difficult wells. Successful execution, however, requires awareness of all aspects throughout the drilling process and full integration of the entire well construction team. Even best laid plans can encounter challenges that quickly become insurmountable. Despite being on alert, as is most often the case with MPD wells, misunderstanding subtle signs throughout the drilling process, poorly synchronized execution or untimely technical failures can lead to catastrophic outcomes for the operator. Additionally, it is not until execution when a full understanding of the wellbore sensitivity to pressure swings becomes apparent.

The authors will look at a series of uniquely different wells, all employing MPD but for different technical reasons. Exploration drilling through challenging pore pressure ramps, high angle and horizontal wells across formations highly sensitive to pressure cycling, PMCD wells and wells drilled through very narrow pore pressure and stability window across depleted zones. Analysis of the detailed design during the planning phase, with the information that was known at that time, will lay the foundation of how each well was executed. In each case, the desired outcome was not achieved for reasons unique to the respective project falling outside the core MPD engineering design. Analysis of the failures will identify key lessons learned and show progressive continuous improvement that has made MPD critical to success on future projects and raised confidence of the users.
Microwave Heating: A Feasible Alternative for Drilled Cuttings Drying in Offshore Environments
Authors: Pereira M. S. , Ataíde C. H. , Naufel R. , Panisset C. M. , Sa C. H. , Martins A. L.
Published: March 2013

Drilled cuttings contaminated by Non Aqueous Fluids (NAF's) are a waste from oil well drilling activities. Over the past twenty years, studies have been conducted in order to assess the effects that these contaminated cuttings have on the environment. In Brazil, the environmental offshore discharge threshold for synthetic base is 6.9 % in mass. Microwave shows itself as a promising technology to remove the organic phase of these drill cuttings. This paper presents microwave heating technique as a new method for the treatment of contaminated drill cuttings. For this purpose, it was developed a batch microwave oven with capacity up to 6 kW. In experimental testing the mass input was 6 kg and the microwave oven was airtight. Microwave cuttings remediation was investigated for three different power inputs (3, 4 and 6 kW) at 0.50, 0.60 and 0.70 kWh/kg and for the specific energies ranging from 0.20 to 0.70 kWh/kg at 3 kW. The moisture content in a rehydration was also studied in cutting drying. The process can remediate the cuttings to below 2%, using the specific energy of 0.60 kWh/kg. The cutting drying by microwave heating is more efficient at low powers input. When cuttings that had already been dried were rehydrated and dried a second time it was observed that the smaller the amount of water content the better was the secondary removal of n-paraffin was.
Annular Pressure Build-up Analysis and Methodology with Examples from Multifrac Horizontal Wells and HPHT Reservoirs
Authors: Bellarby Jonathan , Kofoed Sara Sparre , Marketz Franz
Published: March 2013

Annulus pressure build-up (APB) remains an important design consideration for many wells, not just deepwater or subsea wells. This paper outlines a step-by-step methodology for analysing APB issues applicable to any type of well. Analyses of APB scenarios for a tight chalk oil reservoir and an HPHT gas-condensate reservoir in the Danish Sector of the North Sea are used to demonstrate the methodology.

APB is a potentially serious issue with HPHT wells created by annuli that heat up during production. The increased temperatures cause fluid expansion that can potentially over-stress the casing and tubing if not mitigated. Specific issues for HPHT wells are presented.

The significant increase in the use of multi-stage horizontal fracturing systems with open or cased hole packers and ball or intervention operated sliding sleeves creates a fluid contraction threat. Overpressure through annulus fluid contraction caused by cooling has been rarely analysed. A case is shown to disprove a common belief that the fluid external to the sleeves equalizes with the reservoir over the time frame of the stimulation operation which prevents over-pressurization. Failure cases are presented along with the design calculations required to assess the combination of tubing ballooning, fluid contraction / expansion and transient reservoir flow. It is demonstrated that with cases of toe-to-heel stimulation combined with low reservoir permeabilities, significant transient drops in pressure external to the sleeves can occur. This can lead to tubing, sleeve or packer failures.
Performance and Cost Benefits of Environmental Drilling Technologies: A Business Case for Environmental Solutions
Authors: Brantley Lydia , Kent Jennifer , Wagner Natalie
Published: March 2013

Environmental impact has become business critical as we have been unable to crack certain issues to the degree expected for our industry. It is the central challenge for the continued development of shale markets, as it has been offshore. In a customer survey completed in the first quarter of 2012, a diverse group of operators, drilling contractors, and service companies identified their top three challenges for shale development: pricing, inexperienced personnel, and—of paramount importance—environmental impact. The industry recognizes the need for reduced environmental impact, but what do we need to achieve it?

In the aforementioned survey, many operators and drilling contractors expressed looking to oilfield service and supply companies for continued innovation with the expectation that they continue to be to be forward-thinking and present ideas that provide value. The industry has two primary means for reducing environmental impact of its operations: processes (operator and contractor-driven) and equipment (service and supply-driven). This paper proposes that the two must work hand-in-hand. It explores the opportunity to take this further: identifying critical steps such as process design for reduced environmental impact with lower-impact technology and industrial engineering. The dual approach is needed to affect large-scale change.

This paper will examine the positive impact of the implementation of select environmental technology can have on oilfield economics from the perspective of an oilfield equipment, technology, and services provider. It aims to:

Demonstrate a case for environmental solutions Establish the importance of improved environmental performance for market access Identify areas in which operators evaluate environmental impact Discuss the technology opportunities available to operators Recognize and quantify the performance and cost benefits of aforementioned technologies.
A Summary Of Wired Drill Pipe Field Trials And Deployments In Bp
Authors: Edwards Stephen T. , Coley Chris J. , Whitley Nick A. , Keck Richard G. , Ramnath Vishwahnath , Foster Tommy , Coghill Keith , Honey Mark
Published: March 2013

The first use of wired pipe in BP was in early pre-commercial field trials in seven Oklahoma wells in 2004 to 2005 (Reeves et al, 2006). IntelliServ commercialized its networked drillstring or wired pipe with full connectivity to 3rd party downhole tools in early 2007.

BP field trialed the commercial version of wired pipe with a comprehensive suite of BHI's Loging While Drilling (LWD) tools, Measurment while drilling (MWD) and AutoTrak rotary steerable on two Wamsutter (Wyoming) wells in 2007. These wells achieved a number of "industry firsts" including the first use of IntelliServ along string pressure measurements and the first use of real-time high resolution wellbore imaging while drilling.

Since then, BP has deployed wired pipe commercially on more than 14 wells in 4 additional locations (Trinidad, North Sea, Colombia, and Deep Water Gulf of Mexico) representing a good cross section of drilling conditions and challenges (including wellbore stability, hole cleaning, BHA vibrations, formation pressure measurements in depleted zones, complex geology and challenging directional requirements).

This paper is a summary of the above experiences. It includes a discussion of the challenges and solutions in area such as hardware modifications (e.g. wiring top drives, reamers, jars) deployment, logistics, reliability, pipe handling and other operational modifications, surface connectivity and dataflow to shore. The bulk of this paper discusses wired pipe enabled applications while drilling.
Technological Innovation in Riser Tensioner Design Significantly Reduces Risk of Tensioner Overpull and Likelihood of Catastrophic Events
Authors: Watts Bob , Trent David
Published: March 2013

The "riser tensioner" is a primary component in the MODU's, mission critical, marine riser motion compensation system. Over the past decade, direct-acting tensioners have gained acceptance and are replacing wire line systems.

Because of the significantly longer hydraulic power piping runs associated with the popular direct-acting tensioner design and their less-than-efficient equipment piping arrangement, the influence of hydraulic friction (line loss) is significantly increased. This has a direct consequence of delayed system response to heave during normal operation. Delayed response will produce periods of over and underpull during each vessel heave cycle. Overpull has been directly linked to wellhead deformation and riser overload. Increasing riser string tension force range (hysteresis) increases riser string fatigue rate. A comparison analysis of two tensioner configurations, for an "average design" set of vessel heave parameters, shows that a solution exists to significantly diminish these risks.

The dynamic analysis performed compared the industry standard direct-acting tensioner assembly configuration and a modified, patented design that places the air-over-hydraulic accumulator bottles closer to the rods, thus significantly reducing liquid path length and consequential friction losses; mitigating overpull and its risk. Analysis indicates this to be the most effective corrective action for both existing installations and new builds.

Computational fluid dynamics (CFD) was used to analyze the fluid flow paths of a popular direct-acting tensioner configuration and modified direct-acting tensioner configuration. For the peak fluid flow rate associated with the heave, friction head was determined.

The popular configuration modeled can have a pressure variation of ±490 psi. This pressure variation will yield a per- tensioner tension variation (hysteresis) of 234,000 lbf. For a six-tensioner configuration, the heave-motion-induced marine riser string top tension variation can be 1,405,000 lbf. This result is significant. MODUs having this tensioner configuration should be reviewed and analyzed soonest. The modified configuration has a pressure variation of ±80.2 psi. This variation yields a per-tensioner tension variation (hysteresis) of 38,300 lbf and 230,000 lbf top-tension variation. Retrofitting the modified, direct-acting tensioner is an attractive, corrective action.
New Technology Enhances Rotary Steerable System performance and Provides Superior Borehole Quality and Reduces Vibration in Rotary Steerable Applications
Authors: Barton S. , Herrington D. , Gaines M. , Morrison R. , Stroud D. , Lines L.
Published: March 2013

Rotary steerable systems (RSS) have become a standard technology in today's drilling industry. With the advent of the RSS, have come new challenges associated with well bore quality, steerability, and vibration mitigation. The need for technology that supports and compliments RSS operations is the next logical step in providing optimized RSS drilling services.

While RSS technology allows drilling of extended reach horizontals and challenging well profiles, the systems have their limitations just as mud motors do. The demand for more complex wells has highlighted the need for technologies that can take the advanced capabilities of the rotary steerable system and push it to the next level of performance. A tool that maximizes the effectiveness of an RSS, reduces costs associated with RSS drilling, and improved borehole quality stands to add an entirely new level of value to rotary directional drilling.

A novel technology is now available that has been proven to improve lateral stability and increase bit life by as much as 50% while posting gains in ROP as high as 120% over offset data. Dramatically improved borehole quality has resulted in reduction in materials required for cementing by as much as 25% while reducing the time spent back reaming by 30% and in some cases, alleviating the need for back reaming altogether. Dramatically improved borehole quality in point-the-bit RSS applications. By providing a tighter gauged hole, the severity of downhole vibration and backward whirl were greatly reduced.

This paper provides supporting documentation that a technology proven to improve lateral stability while mitigating damaging downhole vibrations is assisting a major operator in maximizing the performance of their RSS operations and allowing operators a new level of performance and cost savings.
A New Measurement While Drilling System Designed Specifically For Drilling Unconventional Wells
Authors: Krase S. J. , Harvey P. R. , White M. W. , Earl T. G.
Published: March 2013

The recent drilling explosion targeting unconventional reservoirs has created extraordinary opportunities for growth in the oil industry and has also presented many challenges for the MWD industry.

Since the first commercial application of MWD in 1978, significant technological advances have been made. However, most of these advances have been focused on the development of technology for formation evaluation targeting the offshore environment and the higher operating costs associated with this environment.

Most of the existing MWD systems were developed for drilling directional wells through clastic or carbonate reservoirs and are not well suited for drilling unconventional drilling programs. The issues with existing MWD systems are associated with measurement accuracy, measurement type and BHA incompatibility. The requirements for an MWD system for drilling unconventional wells on land are; accurate well bore placement which includes directional drilling and geosteering, drilling efficiency and interfacing into automation systems such as automated top drives and MPD systems.

A new generation of MWD systems has been created specifically for the unconventional drilling environment. Starting with a blank sheet of paper enabled the development of a fit for purpose MWD system that meets the technical and financial requirements for drilling these unconventional reservoirs. The system is designed to fit the existing cost structure associated with drilling unconventional reservoirs on land. The system eliminates the need for dedicated MWD personnel at the wellsite thereby enabling remote directional drilling and also drilling automation. The measurements provided by the MWD system are focused on providing the information required for precise wellbore placement, drilling dynamics for drilling efficiency, annulus pressure to assist with MPD and formation measurements for geosteering. Perhaps most importantly the system is only 34 feet in length which makes it easy to place in the bottomhole assembly.
A Surveillance "Smart Flow" for Intelligent Digital Production Operations
Authors: Al-Jasmi A. , Goel H. K. , Nasr H. , Carvajal G. A. , Johnson D. W. , Cullick A. S. , Rodriguez J. A. , Moricca G. , Velasquez G. , Villamizar M. , Querales M.
Published: March 2013

Intelligent digital oilfield (iDOF) operations include the transfer, monitoring, visualization, analysis, and interpretation of real-time data. Enabling this process requires a significant investment to upgrade surface, subsurface, and well instrumentation and also the installation of a sophisticated infrastructure for data transmission and visualization. Once upgraded, the system has the capability to transfer massive quantities of data, converting it into real information at the right time.

The transformation of raw data into information is achieved through intelligent, automated work processes, referred to here as "smart flows," which assist engineers in their daily well surveillance activities, helping make them more productive and improve decision making. A major oil and gas operator in the Middle East has invested in such an infrastructure and is developing a set of smart flows for key activities and work flows for its production operations, with the ultimate goal of improved asset performance.

This paper explains the development of the production surveillance smart flow, which provides engineers with automated artificial intelligence that analyzes data, provides guidance on well operations, and, when necessary, gives warning and alarms as conditions warrant them. The suite of artificial intelligence consists of advanced correlation statistics, neural-network predictive algorithms, and expert systems.