bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nonaqueous, Salt-Free Drilling Fluid Delivers Excellent Drilling Performance with a Smaller Environmental Footprint
Authors: Walker Jonathan , Miller J. J. , Burrows Kim , Mander Timothy , Hovan Jared 
Published: January 2016

Abstract
Disposal of drill cuttings from nonaqueous drilling fluids (NAF) can be a significant expense and logistical issue for the operator of a drilling rig. NAFs typically contain high levels of salts, commonly calcium chloride or sodium chloride, in the internal phase of the emulsion. These salts are highly beneficial for wellbore stabilization performance but pose issues for disposal of drill cuttings because the salts do not biodegrade and can accumulate in high concentrations in soil.
A salt-free NAF has been developed and field validated in the Western Canadian Sedimentary Basin in Alberta, Canada. The system uses a biodegradable organic to provide an internal phase with equivalent water activity to traditional salt-containing systems. This results in a fluid system with the performance and benefits of a conventional NAF while potentially allowing for greater cuttings disposal options. Depending on local regulations, the system has the potential to reduce environmental and long-term liability concerns by being able to land-farm drilled cuttings without hindering plant growth.
Three wells on a seven-well pad were drilled with the salt-free NAF; the other four with a conventional invert emulsion fluid (IEF). The salt-free fluid performed the same as or better than a conventional fluid while drilling. Observed improvements over conventional NAFs included less required fluid maintenance, greater inhibition of the formation, and less fluid losses in part resulting from reduced oil on cuttings (OOC). A bioremediation study was conducted to analyze the cuttings for electrical conductivity and plant growth. Cuttings were sampled from each type of well and delivered to the lab for testing and analysis. Laboratory testing showed that when mixed with top soil, the salt-free cuttings allowed for viable plant growth. In comparison, the conventional cuttings did not allow plant growth. The paper will discuss in detail the field trial and bioremediation study of the salt-free NAF.
The salt-free system showed equivalent and in some respects better performance to conventional NAFs used on other wells on the same pad. Additionally, cuttings from the salt-free system showed superior plant growth when compared to conventional, salt-containing systems. This system is expected to offer expanded options for cuttings disposal and ultimately reduce the cost and liability associated with using NAFs in many areas.
PMCD Technique Enables Coring & Wireline Logging Operations in Total Lost Circulation
Authors: Houng N. H. , Gallo Zapata J. F. , Ahmad Fauzi M. A. 
Published: January 2016

Abstract
After reaching target depth (TD) with Pressurized Mud Cap Drilling (PMCD) technique, risks associated with total lost circulation (including potential gas migration and unsustainable fluid logistics) have led to the perception that wireline logging and coring operations in PMCD are not feasible. However, with proper planning and procedures in place these operations are possible. Recent carbonate drilling operations in offshore Sarawak, Malaysia, have proven coring and wireline logging operations can be completed in PMCD conditions.
In the first well, Well S, the operator retrieved core samples from three different zones in a gas bearing carbonate reservoir. The coring operation with PMCD, which was the first of its kind in the Asia Pacific Region, created new frontier for carbonate formation evaluation by allowing the acquisition of rock property data from wells once considered to be impossible to drill to TD.
In another well, Well X, PMCD wireline logging operations were conducted safely and successfully. Open hole of 509 m was drilled with PMCD, and upon reaching TD the wireline logging pressure control equipment was rigged up to commence the PMCD wireline logging operation. In addition to the comprehensive planning and execution procedures, the increased riser pressure limitation was a main enabler for the PMCD wireline logging operations. Eight wireline runs were performed, collecting critical data for the field development plan (FDP). The gas water contact for the field was determined accurately despite the total lost circulation.
Running wireline logging and coring operations with PMCD allowed the operator to not only drill once perceived impossible-to-drill wells, but also to retrieve crucial and valuable data from the well at TD. These operations reduce field volumetric uncertainty.
This paper records the planning, execution, and post well analysis of carbonate sections, including the general methodology for the logging and coring operations in PMCD mode, risk and hazard assessment of the operations, results and observations of successful operations in Malaysia with elaboration of issues encountered, and recommended solutions.
Drilling From Onshore to Offshore Targets: Planning and Systematic Execution On An Extended-Reach Drilling Campaign
Authors: Tikkoo Rajiv , Nasarczyk Mark , Akinniranye Goke , Goura Nicholas , Amin Sajid 
Published: January 2016

Abstract
Origin Energy Pty Ltd ("Origin") completed its first extended reach drilling (ERD) project in southeast Australia to access offshore targets from an onshore location. The project targeted the Halladale gas field which is located 5.5 km offshore and 1.8 km below the seabed. For this operator, the challenge was to access offshore reserves using onshore drilling and production infrastructure to minimize project development costs and avoid working in sensitive marine environments.
To mitigate depth uncertainty at the target location, an S-shaped trajectory was selected for the Halladale-2 production well. This started with a shallow kick-off followed by a sub-horizontal section that travelled laterally offshore and ended with a drop-off section to intersect the reservoir target. Advanced drag management techniques were required to drill the 12 ¼-in. and 8 ½-in. hole intervals, install the 9 ⅝-in. production casing, 7-in. production liner, and 5 ½-in. intelligent upper completion. The 9 ⅝-in. casing was installed using the buoyancy-assisted method (floatation), such that it could be "pushed" and "reamed" in the hole beyond the point of negative weight. Due to the geological environment and potential for mud losses, special attention was required in order to have the system designed for reduced hydrodynamic loads and still maintain appropriate mud weight for wellbore stability.
The 9 ⅝-in. casing was run completely empty and required rotation in order to reach total depth. During the operation of landing-out the casing on the well head, the use of rotation to overcome axial drag was not an option; therefore, adequate contingency planning was required. A casing selective floatation collar was installed to provide additional weight should it be required by filling the top portion of the string with drilling fluid as total depth was approached. This allowed the lower portion of the casing in the high angle interval of the wellbore to remain empty, and thus neutrally buoyant. This contingency was in addition to the risk assessed push-down weight that the top drive could provide. A process was adopted to ensure that every member of the team understood the program and was committed to the successful delivery of the wells. These measures resulted in significant cost savings for the project.
Technical challenges were overcome with design solutions and operational practices developed with the aid of modeling and simulations performed during the planning phase. The preparation of comprehensive multi-well program, the use of real-time data to validate the engineering models and a systematic approach to well planning contributed to the success of the project. When the rig limitation is accounted for, the Halladale-2 ERD well was a world-class challenge that was successfully overcome.
A New Damping Model for Nonlinear Drillstring Dynamics: Understanding the Effects of Rotation, Eccentricity, and Confined Fluid Flow and Their Impact on Unconventional Drillstring Design
Authors: Wilson J. K. , Noynaert S. F. 
Published: January 2016

Abstract
Since the pioneering work of Bailey and Finnie in 1960, drillstring dynamics continues to be an active area of research within the industry. While much effort is put into developing accurate descriptions of the complexities associated with the downhole environment, proper modeling of the various damping mechanisms acting on the drillstring remains underdeveloped. A typical approach to modeling the damping downhole consists of utilizing a generalized, or proportional, damping model based on measurements of the actual system response. This technique can be fairly useful when done properly but does not actually quantify the effects of various environmental or operational parameters, such as fluid characteristics or string rotation, on the overall behavior of the drilling assembly.
This study presents a nonlinear, semi-analytical, fluid-force model specifically developed to account for the various downhole characteristics that contribute to energy dissipation such as pipe eccentricity, lateral velocity, rotation speed, fluid rheology, and flow rate. This new fluid-force model is combined into an already proven drillstring model which was developed to embody the fully coupled flexibility of the drillstring, arbitrary wellbore curvature, frictional contact, and complex tool geometry. Using the improved model, the paper analyzes the nonlinear behavior of drillstrings with a focus on lateral vibrations in modern unconventional wellbores. Specific attention is given to studying the damping effects on the dynamic response of the drillstring and BHA during rotation with a Rotary Steerable System (RSS).
The results shown through this investigation help to quantify the dynamics associated with modern drilling operations. Effects of fluid properties, flow rate, and rotation speed on the nonlinear behavior of the drillstring are examined through numerical studies of rotating an RSS assembly in an unconventional horizontal wellbore. Through the results, it is shown that proper modeling of the fluid forces acting on the drillstring helps to explain how BHAs, under certain conditions, can be safely operated within a range of resonant frequencies. Advanced visualizations of these time-domain simulations also reveal a unique observation that could have a significant influence on expanding the drilling envelope in automated operations.
Innovative Conical Diamond Element Bit Significantly Reduces Drilling Cost of Williston Basin Three Forks First Bench Laterals
Authors: Schilling John , Cooley Emy , Azar Mike , White Allen , Koffler Kerry , McDonough Scott , Self Jordan , Krough Brad , Bits Smith 
Published: January 2016

Abstract
The Three Forks First Bench (TF1) in the Williston Basin is attractive to operators for its production qualities; however, the formation is problematic for drilling with polycrystalline diamond compact (PDC) bits. TF1 is an interbedded dolostone, 30 to 40 ft thick, capped by the abrasive Pronghorn/Sanish formation with high stress variations/spikes and laminations. These formation characteristics lead to cutter damage and vibration, which cause slow rates of penetration (ROP) and additional trips due to bit/bottomhole assembly (BHA) failure.
In response to these challenges, a revolutionary rock-removal system has been designed. The system implements conical diamond elements (CDE) to work in unison with the PDC cutters. Conventional PDC bits complete a typical 10,000-ft TF1 lateral in a one-bit/BHA in only one out of five wells. The most common reason for tripping is bit/BHA failure due to the harsh characteristics of the TF1. The CDE's unique geometry applies a concentrated point load to fracture formation more efficiently, and its ultra-thick diamond layer provides superior impact strength and wear resistance. Bits utilizing CDEs in conjunction with PDC cutters are known as CDE bits. They are able to withstand the demands of the application where conventional PDC bits cannot.
CDE bits average 5,447 ft at 83 ft per IADC hour when placed as the first bit in a lateral. That performance is 10% farther and 15% faster than conventional PDC bit offsets. Analyzing measurement while drilling (MWD) tool vibration data, CDE bits have proven to mitigate BHA vibrations compared to conventional PDC bits. These performance step changes have helped operators improve their one-bit/BHA TF1 lateral success rate from one out of five wells with conventional PDC bits to an astounding one out of three with CDE bits.
One operator in particular has utilized CDE bits to their full potential. From September 2014 to September 2015, the operator's one-bit/BHA total depth (TD) rate using conventional PDC bits was only 13%. However, the 1-bit/BHA rate when CDE bits were used was 83%, which provided a considerable savings in eliminating the nonproductive time (NPT) in tripping. Depending on the depth, a trip could cost the operator USD 80,000 and 16 hours in NPT. The average performance of CDE bit drillouts has been 9,538 ft at 137 ft per on-bottom hour, providing a 74% improvement in footage and a 2% improvement in ROP over conventional PDC bits for the operator. The reduction in NPT in tripping and improvement in drilling performance has led the operator to prefer drilling with CDE bits.
Changing Drillstring Design to Allow Accurate Calculation of BHA SAG Corrections
Authors: Hinke Sean , Kanji Karim , Mracek Brian , Slight Chris , Happy Robin , Zabcic Lidia , Relph Diver 
Published: January 2016

Abstract
Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) drilling environments in Northern Alberta have some of the tightest geological control in the world. In many cases, there are multiple stratigraphic wells along the length of the vertical section of the horizontal legs. This geological control allows wells to be more accurately positioned with formation evaluation sensors than in most areas, which often means that the resulting wellbore position from directional surveys, containing compounding survey uncertainty, places the wells differently than expected from the geological wellbore positioning. Through empirical testing in controlled environments and field validation trials, it was determined that small changes in the bottomhole assembly (BHA) design can greatly reduce the deflection of BHA components and the impact it has on the misalignment of the directional sensor, otherwise known as BHA SAG. These small changes to the BHA allow the current industry modeling software to more accurately predict the BHA deflection, providing the most accurate survey inclination corrections possible.
Testing was performed comparing different combinations of hole size and tool size on assemblies that contained external upsets to better determine the effects of SAG when using flex collars and stiffer slick collars with a constant diameter. Through empirical testing, it was determined that flex collars deflect in a manner which BHA modeling is unable to predict when external upsets are present. External upsets can include stabilizers, wear bands, worn BHA components, crossover subs, and reducing OD on BHA components. When modeling the flexure across the length of a flex collar or other complex BHA components, it results in a reduction in accuracy when predicting deflection of the BHA in the vicinity of survey instruments. Using collars with a constant diameter circumvents this issue; eliminating variations in diameter across the length of a component allows modeling software to predict the deflection, providing the most accurate results. The results of this study can provide the industry with a best practice to manage and reduce this effect until the modelling has advanced sufficiently to account for the SAG inaccuracy.
Reduce P&A Cost with Section Milling Technology
Authors: Ghegadmal Tejas , Ponder Andrew 
Published: January 2016

Abstract
A firm commitment to environmental safety calls for abandoning wells with depleting production by setting a competent cement plug in the wellbore per government regulations. To prepare the wellbore for the cement plug, concentric casing strings must be removed. When cutting and pulling the casing is not possible, it must be milled away. Milling the casing requires numerous trips into the hole, substantially raising the cost to plug and abandon (P&A) a subsea well.
A conventional section mill, used to accomplish milling, has stabilization features sized close to the inside diameter of the milled casing. Multiple knives expand outward, radially far enough to mill a single casing string. Stabilization features reduce milling vibration, but their gauge-diameter prevents them from passing through some restricted-diameter tubulars that can exist above the wellbore. Reducing the gauge diameter of the mill to pass through restrictions compromises its performance and reliability. Because of the subtle nature of its stabilization features, conventional section mills are referred to as "passively stabilized". A new undersized section mill with "active stabilization" can be deployed through a restricted-diameter tubular to mill a section of casing string below it with similar performance and reliability of the conventional mill.
This new actively stabilized section mill was used to mill a 70-ft. section in 11-3/4 in. casing below a restricted-diameter production riser. The mill passed through the restricted inside diameter of the riser and blowout preventer (BOP). It then expanded its stabilizer arms to centralize itself inside the casing before cutting knives expanded to begin the cut. Cutting knives slowly expanded as they cut through the casing wall, and then milled down the unwanted casing section. The stabilizer arms kept the undersized mill firmly centralized inside the milled casing, limiting lateral vibration of the mill. Leaving the riser, BOP and surface equipment in place saved the operator 3 days and USD 1 million.
Active stabilization reduced vibration, improved milling performance and knife longevity, thus reducing the number of trips to mill a section of casing, substantially reducing costs and HSE risks of P&A.
Pipe Sticking Prediction Using LWD Real-Time Measurements
Authors: Hess Joshua 
Published: January 2016

Abstract
In addition to formation evaluation, logging-while-drilling (LWD) measurements can also be used as a real-time solution to issues that arise during drilling. For example, LWD measurements can be interpreted to help determine if increasing mud weight is useful or if the rate of penetration (ROP) must be slowed. What if measurements made with LWD tools can help predict whether or not a drill string will become stuck while drilling? This paper describes a model that was created to predict situations with high risk of the tool becoming stuck so they can be addressed during the planning and execution phases. The model learns, or builds on each job experience, to improve future decisions.
Most experienced individuals involved in the drilling process understand the various ways that a drill string can become stuck and factors that contribute to it becoming stuck. Many variables are attributed to a bottom hole assembly (BHA) becoming stuck during drilling operations. This paper explains the variables that were used in the model and why they were used. Some measurable variables are wellbore characteristics, BHA characteristics, downhole pressure and temperature, drilling practices and mud properties. These variables were gathered from 42 wells drilled on the Gulf of Mexico (GOM) shelf. More specifically, the information was gathered from end-of-run reports, annular pressure (AP) logs, LWD databases and surveys.
After the model was created, the model was tested against seven additional GOM shelf wells. The model predicted correctly that in three of the seven wells, the drill string would be permanently stuck. In another three of the seven, the drill string was temporarily stuck while the model claimed it would be permanently stuck. In the final well, the model predicted that the drill string should be stuck, while it was not; however, the client made decisions while drilling the section which indicated that they were fearful of getting stuck.
If it can be shown that there is a risk of the drill string becoming stuck in a well, preventative as well as after-the-fact measures can be used to adjust the mud system and other drilling parameters. Additionally, fishing services can be prepared early or even moved to location earlier to cut down on non-productive time (NPT). A model such as this provides an indication of the need to try preventive measures to mitigate the situation before the problem occurs, or at a minimum provides additional information so that the best course of action can be taken.
A New On-Command Integrated Expandable Under Reamer Technology Enabled Unique Drilling Solutions: Lowering Operational Risks and Saving Operational Cost
Authors: Fang Lei , Manseth Arvid , Stue Kjell , Johansen Bjørn-Ståle , Skappel Jan Arild 
Published: January 2016

Abstract
This paper presents the technical features and the associated benefits of a new integrated expandable under reamer technology, and showcases the field testing of the technology in the Brage field at offshore Norway and the achieved results.
Historically, the overburden stratigraphy at Brage field has been challenging for drilling. The unstable green clay and Draupne shale formation, the casing and completion programs and Equivalent Circulation Density concerns associated with drilling extended reach wells necessitate hole enlargement while drilling. In particular, the 12 ¼″ section has a planned Total Depth (TD) right below the Draupne shale, inside which the calcite stringers also present, and a near bit reamer significantly increases the likelihood of getting down the 10 ¾" casing.
A new integrated under reamer technology was utilized to address the challenges in drilling five sections of a well in Brage: 14 ¾ ″ × 17 ½″, two 12 ¼″ × 13 ½″ sections and two 8 ½″ × 9″ sections. The new under reamer is fully integrated with the company's rotary steerable system, which enables unlimited on-demand activation and deactivation cycles through downlinking with each cycle taking less than 5 minutes, flexible and optimal placement of the reamer in the bottom hole assembly (BHA), and real time feedback from downhole. The flexibility of the placement in BHA allows the under reamer to be used as a near bit reamer, a main reamer, or both. When used as a near bit reamer, the reamer can reduce the rat hole length to a minimum of 4 meters in the same drilling run, eliminating the need of a dedicated rat hole elimination run. The real time feedback includes confirmation of the blade activation status and a hole opening diameter log, reducing operational uncertainties for under reaming and saving rig time for a shoulder test that is otherwise required.
The technology proved its effectiveness as a reliable main reamer as well as a near bit reamer for rat hole elimination while satisfying all requirements for directional drilling and enabling Measurement While Drilling (MWD) and Logging While Drilling (LWD) measurements. For the 12 ¼″ × 13 ½″ section, both main and near bit reamers were activated simultaneously while drilling the last 68 m to TD and a good drilling performance was observed from the run.
The new technology provides unique features such as unlimited cycles of activation and deactivation through downlinking, flexible placement in the BHA and real time confirmation of blade activation status and hole opening diameter. The paper will describe these features in detail, and demonstrate how they can help the operators to reduce operational risks and save cost. It will also showcase a unique drilling application where three cutting / reaming elements in the BHA are actively present simultaneously and the associated drilling performance.