bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fluorous-Based Drilling Fluid for Ultra-High-Temperature Wells
Authors: Galindo Kay A. , Deville Jay P. , Espagne Bernard Jean-Luc , Pasquier David , Hénaut Isabelle , Rovinetti Sara 
Published: June 2014

Abstract
The growing industry demand to operate in high-pressure/high-temperature (HP/HT) environments (&gt;10,000 psi and &gt;350°F) requires robust drilling fluid performance to facilitate drilling under such harsh conditions. Several water-based and synthetic-based drilling fluids have met these high temperature operational challenges. However, despite the thermal stability of these fluid systems, deeper exploration has prompted the need for new technologies to drill in ultra-high-temperature reservoirs (&gt;450°F). A fluorous-based drilling fluid can help meet these demands because fluorous materials are well-known to function in harsh chemical and thermal environments. Fluorous materials are composed of a carbon framework that is highly saturated with fluorine atoms. The increased electronegativity of fluorine relative to hydrogen provides fluorinated materials unique properties compared to their hydrocarbon counterparts.
Fluorous fluids and additives exhibit thermal stabilities upward of 600°F. The properties of fluorinated materials could assist drilling operations by increasing thermal stability, improving lubricity, minimizing corrosion, stabilizing shale, and increasing contamination resistance. However, because of the water- and oil-repellant nature of fluorous materials, conventional drilling fluid additives do not perform. The high inherent density of fluorous liquids allows fluorous drilling fluid to be formulated at high densities (16.0 to 20.0 lb/gal). Only 7% by volume barite loading was necessary to achieve 16.0-lb/gal density with the fluorous fluid, compared to 27% by volume barite loading required to prepare a 16.0-lb/gal water-based mud. A fluorous surfactant provided emulsion stability, and the required concentration was optimized for the fluorous-based fluid.
This paper presents the detailed laboratory study of a new fluorous-based drilling fluid that was formulated with 16.0-20.0 lb/gal densities, adequate suspension, and reasonable rheology with some degree of filtration control. Emulsion stability, rheological properties, suspension, and filtration control provided by the new drilling fluid system are also discussed. The fluorous-based drilling fluid potentially provides an ultra-high-temperature stable drilling fluid solution that can readily function in ultra-high-temperature wells.
Ream-On-Demand System Eliminates Dedicated Trip to Enlarge Rathole in Deepwater Gulf of Mexico Operation
Authors: Lirette Nicholas , Aubin Mike , Davis Jefferson , Duvvuru Hari , Nagaraj Mahavir 
Published: June 2014

Abstract
Hole enlargement while drilling (HEWD) is a frequent and well established practice in deepwater Gulf of Mexico operations. The most common BHA design positions a concentric underreamer above the complex MWD/LWD string to enable activation, increase stability and to ensure the enlarged borehole does not degrade LWD image quality. However, this conventional BHA configuration for HEWD results in a rathole of approximately 160 ft at TD. To open the rathole to an adequate size to accommodate the subsequent liner string, the operator is forced to trip the drilling BHA back to surface and perform a dedicated hole-opening run. This procedure is costly and can add a day or more to the well construction timeline. In a recent offshore well, the operator wanted to eliminate the trip to enlarge the rathole and land the liner shoe closer to the section TD.
To accomplish the objective, a dual reaming BHA system was developed with a conventional 12¼-in x 14½-in expandable underreamer deployed above the MWD/LWD and a new ream-on-demand (RoD) system positioned between the RSS and MWD. The RoD tool is equipped with an innovative hydraulic system that can perform multiple activations/deactivations of the cutting blocks. Because the RoD system does not require a ball drop to engage, BHA design flexibility is greatly enhanced.
Optimal tool configuration was determined by modeling the BHA with an FEA-based engineering system. The directional response of the RSS was also modeled to ensure the placement of the RoD system did not interfere with RSS directional capabilities. The RoD cutter blocks were configured to be passive when retracted to enable the underreamer to act as a control stabilizer providing a pivot-point for the push-the-bit RSS. At section TD, the plan was to pull the RoD tool above the rathole, activate the RoD cutter blocks and enlarge the 12¼-in hole to 14½-in as required.
The new tandem underreamer BHA was deployed on the deepwater project and drilled 1221 ft of section in 14.45 hrs at an average ROP of 110 feet per hour, while opening the 12¼-in pilot hole to 14½-in with the conventional underreamer. After reaching TD, the RoD system enlarged the 153 ft rathole from 12¼-in to 14½-in in only 3.5 hrs. The utilization of the dual hole opening system, in conjunction with an MWD/RSS eliminated the need to perform a dedicated rathole run to achieve the desired liner shoe depth. This paper covers the application the RoD system, tool design and pre-job risk assessment which saved the operator 16 hrs of rig time and reduced project costs by approximately $625,000 USD.
Shale Play Development Program Using Risk-Reward Mapping from Geospatial Analyses
Authors: Chorn Larry , Yarus Jeffrey , Rosario-Davis Suzanne del 
Published: June 2014

Abstract
Finding the best drilling locations in an extensive shale play holding is key to achieving production profile expectations and good economic metrics. Shale plays have been described as statistical plays. However, it becomes increasingly unacceptable to drill disappointing, underperforming wells as the operator and partners move from the exploration lifecycle stage into the appraisal and field development stages.
The physical and chemical properties of shales dictate the economic success of development drilling programs. It is recognized that at least seven parameters must fall within empirically-determined ranges for a play to have economic production rates and estimated ultimate recovery (EUR) exceeding threshold internal rate of return (IRR) requirements.
A geostatistical shale property workflow that high-grades 160-acre sections in a regional shale play, using a limited number of wellbores with standard logging suites is demonstrated. This paper extends the workflow from high-grading drilling targets to quantitative risk assessment. An application of the workflow to a multi-square mile U.S. shale play illustrates the analysis and its interpretation. The example shows that down-spacing well density in high-graded sections (high potential reward) is a quantitatively lower risk investment program than would normally be expected. Typically high reward opportunities, in the investment world, are expected to represent higher risk as well. Geostatistical analysis in the example play shows just the opposite behavior because the statistical nature of the local shale quality can be mapped and profitably drilled.
Exploiting this geostatistical, high-grading workflow can accelerate an operator's development program with higher rewards, lower risk, and better rates of return than pursuing a uniform development program over a large regional play.
Make Decision on the Fly: A New Method to Interpret Pressure-Time Data during Fracturing – Application to Frac Pack
Authors: Pirayesh Elias , Soliman Mohamed Y. , Rafiee Mehdi 
Published: June 2014

Abstract
Real time analysis of fracturing data is an invaluable tool for determining whether a fracturing job is progressing as planned. Therefore since the early days, understanding of fracturing pressure as a readily available diagnostic tool has been emphasized and practiced by the industry. Theories and techniques were developed for the interpretation of such data e.g. Nolte-Smith (1981).
The well-known Nolte-Smith method (1981) analyzes the pressure response of a formation during pumping, in order to predict the fracture geometry being created. Although this technique provides a highly reliable tool in terms of interpreting fracturing events, but in real time practices, it can take this technique quite a long time to detect a change in fracture behavior. This is partly due to the data compression associated with the Nolte-Smith log-log plot. Also Nolte-Smith technique necessitates prior knowledge of closure pressure of the formation which is not always known.
In this paper, we present a new method to analyze and interpret pressure-time data during fracturing. This method, which is based on a modification of Nolte-Smith technique, has proven effective in precisely interpreting fracturing behavior while the job is being carried out. Additionally it eliminates the short-comings of the original technique, as discussed above; meaning that the proposed method permits quick and accurate interpretation of fracturing data plus it needs no prior knowledge of formation in-situ stresses. This has been reached by a new innovative moving-reference-point concept assembled with a mathematical manipulation of the power-law fracture propagation theory.
Application of the new technique in the analysis of a variety of field cases including several frac packs and regular fracturing treatments has proven quite successful. First accurate pressure-time matches were obtained and then using these matches, the Nolte-Smith parameters were determined which in part allowed detection of fracture behavior changes (e.g. propagation to width-gain) usually in less than a minute and sometimes even in a few seconds of the start of the event.
Ten Years' Experience with Flare Gas Recovery Systems in Abu Dhabi
Authors: Saadawi Hisham 
Published: June 2014

Abstract
Abu Dhabi Company for Onshore Oil operations (ADCO) is one of the major oil producing companies in the Arabian Gulf. The Company produces oil from a large number of reservoirs in various fields which are different in size and are under different stages of depletion.
In order to achieve near zero flaring and reduce emission, the Company began implementing several projects for flare gas recovery in its oil fields more than ten years ago.
Various compressor technologies were selected to suit the specific field applications. These included: liquid ring, sliding vane compressor, both dry screw and oil-wet screw compressors as well as ejectors.
Methods adopted to ensure positive pressure on the flare recovery system while preserving a path to the flare for emergency relief included: a water seal drum, a SIL rated quick opening valve, and a pilot-operated relief valve.
The paper presents comparison between the designs of the various systems; compressor technologies and pressure relive methods used in flare gas recovery systems. Applicable codes and standards are discussed. The paper also addresses some of the lessons learnt and the guidelines on best practice for selecting and designing vapor recovery systems.
Case Study - ECD Management Strategy Solves Lost Circulation Issues On Complex Salt Diapirs/Paleocene Reservoir
Authors: Murray David , Sanders Mark W. , Houston Kirsty , Hogg Hamish , Wylie Graeme 
Published: June 2014

Abstract
Drilling horizontal infill wells in the Pierce field in the UK Central North Sea is challenging due to the narrow drilling window caused by depletion in a highly fractured reservoir, which is further complicated by water injection and the proximity of other production wells. Wellbore strengthening was attempted in the reservoir section of Pierce B5, although, when a pre-existing fracture further weakened by depletion was encountered, losses occurred. During the next ten days over 5,000 barrels of non-aqueous fluid (NAF) were lost downhole. During the recovery from the losses event, 15 individual treatments with loss circulation materials (LCM) were made. More than 50MT of LCM was used without success, however, the well was stabilised enough to secure the drilled footage and complete the well.
Two additional horizontal wells in the same field were successfully drilled using a low-equivalent circulating density (ECD)-management strategy combined with the development of a low-ECD drilling fluid system and the use of a high-fluid-loss, high-strength (HFHS) pill. The dual problems of barite sag and poor hole cleaning, that can be problematic when reducing ECD, were successfully managed. This low-ECD technique can be applied in other subsea depleted wells where narrow drilling windows exist.
This paper describes how a detailed analysis of the losses event on Pierce B5 provided an improved understanding of the loss mechanism resulting in a revised ECD management strategy. An engineered low-ECD NAF with a HFHS pill combined with learnings on ECD awareness in the planning and execution phases mitigated the drilling risks on subsequent wells. This has implications when encountering very large fractures that are difficult to overcome, not only on future Central North Sea wells, but also has wider global significance for wells drilled in similar geological settings.
Three-Phase Relative Permeability Modeling in the Simulation of WAG Injection
Authors: Zuo Lin , Chen Yuguang , Zhou Dengen , Kamath Jairam 
Published: June 2014

Abstract
We propose a new workflow to evaluate the impact of three-phase relative permeability models on the simulation of Water-Alternating-Gas (WAG) injection – define a root-mean-square error to quantify differences between the models; introduce a high-uncertainty region on a ternary saturation diagram; and map simulation saturation-time paths in this ternary diagram. The display of the saturation paths, along with the high-uncertainty region, allows us to systematically analyze and understand the impact of three-phase models on recovery predictions. We apply the workflow to immiscible and miscible WAG injection, simulated using black-oil and compositional models. Both 2D homogeneous cases (with various reservoir conditions and injection scheduling), and realistic 3D field sector models are considered. We show that the three-phase relative permeability models can have a strong impact on recovery predictions for immiscible WAG injection, and the impact depends on initial conditions and displacement history. For compositional simulation of multi-contact miscible WAG injection, the impact of three-phase models depends on the size of the three-phase flow region before the miscibility fully develops. Simulation of CO2 flooding on a 3D field sector model reveals that the uncertainty in recovery predictions due to the various three-phase models is secondary compared with other sources of uncertainty (e.g., the input two-phase relative permeability data), and this may be the case in other field studies.
Three-Phase Relative Permeability Modeling in the Simulation of WAG Injection
Authors: Zuo Lin , Chen Yuguang , Zhou Dengen , Kamath Jairam 
Published: June 2014

Summary
We propose a new workflow to evaluate the effect of three-phase relative permeability models on the simulation of water-alternating-gas (WAG) injection: define a root-mean-square error to quantify differences between the models; introduce a high-uncertainty region on a ternary saturation diagram; and map simulation saturation/time paths in this ternary diagram. The display of the saturation paths, along with the high-uncertainty region, allows us to systematically analyze and understand the effect of three-phase models on recovery predictions. We apply the workflow to immiscible and miscible WAG injection, simulated by use of black-oil and compositional models. Both 2D homogeneous cases (with various reservoir conditions and injection scheduling) and realistic 3D field sector models are considered. We show that the three-phase relative permeability models can have a strong effect on recovery predictions for immiscible WAG injection, and the effect depends on initial conditions and displacement history. For compositional simulation of multicontact miscible WAG injection, the effect of three-phase models depends on the size of the three-phase-flow region before the miscibility fully develops. Simulation of carbon dioxide (CO2) flooding on a 3D field sector model reveals that the uncertainty in recovery predictions because of the various three-phase models is secondary compared with other sources of uncertainty (such as the input two-phase relative permeability data), and this may be the case in other field studies.
Comparative Study for the Interpretation of Mineral Concentrations, Total Porosity, and TOC in Hydrocarbon-Bearing Shale from Conventional Well Logs
Authors: Adiguna Haryanto , Torres-Verdín Carlos 
Published: June 2014

Abstract
The estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method.
This paper introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties.
This paper documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and neutron-capture spectroscopy (NCS) logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition.
Multilateral Wells in the Urucu Field of Western Brazil: Reducing Environmental Impact in the Amazon
Authors: Mendes Sandro , Albuquerque Marcelo , Vento Mario , Batista Nazildo 
Published: June 2014

Abstract
The operator assessed many technologies to increase production, and reduce costs while protecting the environment in the Brazilian Amazon. For this project, where access to likely well sites is restricted both by limited infrastructure and Brazilian regulations, the operator chose environmental impact as the primary factor in their decision process.
To address both environmental and production issues, the operator selected multilateral technology which minimizes the well site footprint yet allows for drainage of a much larger volume of the reservoir from a single surface location. This is a significant advantage when compared to the cost and environmental impact of drilling multiple wells or using large drilling pads.
The operator implemented this technology in the Urucu field, located 650 km southwest of Manaus, in the heart of the Brazilian Amazon. The field is made up of three reservoirs called ‘River Urucu’ (RUC), ‘East of Urucu’ (LUC), and ‘Southeast of Urucu’ (SUC).
The Urucu has 95 oil producing wells and 6 gas injection wells. The target formation is Jurua in the Paleozoic Solimões basin–a basin that includes an important petroliferous system called Jandiatuba-Jurua. The reservoir rock consists of eolian and marginal marine carboniferous sandstones.
This paper presents the results of a successful multilateral technology project in the Urucu field in which three TAML Level 4 dual-lateral wells were installed by the operator. Those wells had an average production rate of 1.75 times more than a typical horizontal well while spending only 1.42 times the average cost of the same.
Geomechanical Modeling of Wellbore Stability in Salt Formations
Authors: Wang Han Yi , Samuel Robello 
Published: June 2014

Abstract
Exploration drilling is venturing out into deeper regions of water. While exploring these deeper water depths, large hydrocarbon deposits have been found below salt formations. These reservoirs are located in formations called "pre-salts," which are located below the salt formations. Pre-salt reservoirs have been found in offshore Brazil, the Gulf of Mexico, West Africa, and the North Sea. Completions in salt formations can be difficult owing to the creep behavior that the salt formations exhibit. Creep behavior results from the instability of the salt formation, which causes a slow flow and permanent deformations. Creep deformation occurs over time and is initiated once the salt formation has been penetrated. Completion of the wellbore does not stop formation creep. The constant creep of the salt formation causes excess stress on the wellbore casing, which may eventually cause the casing to collapse. In this study, a 3D geomechanical model is developed, using data such as wellbore pressure and temperature, formation stress and temperature, rock, cement, and casing properties, to predict the effects of salt creep behavior on stress loading in the wellbore casing, which helps to assess the life expectancy of wells in pre-salt reservoirs. The simulation results of this model can provide quantitative results of casing stress and deformation as a function of time under various temperature, in-situ stress and operation conditions, that can be used as useful information for subsequent wellbore casing design and wellbore integrity analysis. In addition, possible methods that can mitigate the severity of salt mobility and reduce the risks of casing collapse are discussed.