bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Pragmatic Approach to Understanding Liquid Loading in Gas Wells
Authors: Riza M. F. , Hasan A. R. , Kabir C. S. 
Published: October 2014

Abstract
Liquid loading is the inability of a producing gas well to remove its coproduced liquids from the wellbore. The liquid flowing as droplets or film accumulates at the well bottom, thereby imposing backpressure at the sandface and triggering increasingly higher pressure loss in the wellbore. The problem initiated by liquid loading is manifested in terms of loss in well deliverability, causing the wellhead pressure (WHP) to decline significantly, which, in turn, leads to the cessation of gas production. Accordingly, the liquid-loading issue reduces the ultimate recovery of a gas well.
Both the droplet-flow reversal and liquid-film–flow reversal have been postulated to be the underlying mechanism for liquid loading. Both mechanisms are predominantly premised on diagnosing the problem at the wellhead flow conditions. This study explores the deliquefication issue in a gas well by fluid and heat flow modeling of the entire wellbore for a variety of flow situations in gas and gas/condensate reservoirs.
We observed that when a well experiences annular two-phase flow throughout the wellbore, no liquid loading occurs. The transition from annular to churn or slug flow initiates the liquid-film–flow or droplet-flow reversal, thereby triggering liquid loading. Most often the flow condition at the well bottom controls the onset of liquid loading. Using three published datasets, we showed that the understanding of liquid loading improved when the entire wellbore flow modeling was used. Forward modeling suggested that the tubing inside diameter (ID) and the well productivity index (PI) are the most important independent variables in determining the critical liquid loading rate and the onset of liquid loading.
Advanced Drilling Dynamics Sensor Allows Real-Time Drilling Optimization, Damage Prevention and Condition Monitoring of RSS and LWD BHAs
Authors: Lines L. A. , Mauldin C. L. , Hill J. W. , Aiello R. A. 
Published: October 2014

Abstract
This paper outlines the development and field deployment of the latest drilling dynamics sensor and validation of two preventative maintenance algorithms.
The papers prime focus is torsional dynamics and the insight gained through the application of a novel angular rate gyro. The unique abilities of this sensor to measure angular rotation rate are used to characterize four distinct modes of torsional vibration. Downhole data is also shown which proves instantaneous reverse rotation of the bit against the rock face can occur when severe high frequency torsional vibration is present.
The paper validates a new metric dedicated to detecting high frequency torsional dynamics. This metric, when used in combination with a unique Torsional Dynamics Indicator and downhole frequency analysis measurement, allows real-time determination of the mode and damaging nature of all types of torsional vibration. This knowledge is vital in order for appropriate mitigation strategies to be followed and for downhole tool damage to be understood.
Preventative maintenance schemes for vibration and hole curvature are discussed and case studies show how these objective metrics can be used to track downhole conditions to (1) determine when downhole conditions exceed recommended guidelines, (2) investigate the effectiveness of vibration mitigation strategies and (3) objectively quantify differences in the downhole drilling environment.
Experimental Investigation on Wellbore Strengthening in Shales by Means of Nanoparticle-Based Drilling Fluids
Authors: Contreras Oscar , Hareland Geir , Husein Maen , Nygaard Runar , Alsaba Mortadha 
Published: October 2014

Abstract
Wellbore strengthening (WS) is the mechanism of increasing the fracture pressure of the rock at depth. Applications of WS in the drilling industry enable safe drilling by preventing mud losses, drilling in narrow mud windows, accessing reserves in depleted reservoirs, and also have the potential to reduce the number of casing strings. Most of WS applications have been done for sandstones. In fact, a common industry thought is that a permeable formation is the only medium that allows WS occurrence. WS in shale formations is a controversial topic in the drilling industry due to the poor understanding of the mechanism and limited field success on strengthening of low permeability formations. This paper presents an experimental research work where a significant fracture pressure increase was achieved in shale and the predominant WS mechanism was identified. The main implication of this work is that WS can occur in shale formations using oil based mud (OBM) with the addition of nanoparticles (NPs) and graphite.
Fracture pressure increase was quantified by conducting hydraulic fracturing tests on 5 3/4″x9″ Catoosa shale cores. A 9/16″ wellbore was drilled, cased and cemented. Overburden and confining pressures were applied on the cores to simulate a normal-faulting regime. Two injection cycles were applied allowing 10 min for fracture healing after the first cycle. The fracturing pressure was increased by 30% when calcium-based NPs (NP2) were used, whereas iron-based NPs (NP1) resulted in 20% increase. The optimum NPs concentrations were experimentally identified. A strong relationship between WS and HPHT filtration values was observed. Optical microscopy, scanning electron microscope (SEM) and energy dispersive X-ray spectroscopy (EDX) analyses were conducted on the cores post-testing. The fractures were found to be completely sealed from wellbore to tip. The seal was developed due to the carrier fluid penetration through the induced fractures and NPs attachment on the fracture faces. This was corroborated by the estimation of the pore throat aperture of the shale at the testing pressure. Tip isolation by the development of an immobile mass was identified as the predominant WS mechanism. A 20 micron-seal containing homogenously distributed NPs and graphite was formed. According to the post-testing analysis of cores and injection pressure, WS initially occurred in a certain wellbore direction and a second injection cycle forced the fluid to follow a different direction creating a second vertical fracture. An average angle of 30° was observed between the hydraulic fractures.
Feasibility and Evaluation of Surfactants and Gas Lift in Combination as Severe Slugging Suppression Method
Authors: Sarica C. , Yuan G. , Shang W. , Pereyra E. , Kouba G. 
Published: October 2014

Abstract
An experimental study of severe slugging suppression utilizing a combination of surfactants and gas-lift was conducted using a facility consisting of a 3-in. ID, 65 ft long, -3° inclined flow line followed by a 45 ft long vertical riser system. Air and water were used as fluids. The surfactant used was a foaming agent capable of forming stable foams in all brines for a wide range of pH. Pressure behavior in the flow line – riser system was monitored and input gas, injection gas, liquid and surfactant flow rates were continuously measured. In addition, visual observations were made to identify severe slugging. Effects of the proposed method were quantified with a modified elimination performance index (MEPI) considering not only pressure fluctuations but also back-pressure effects.
A total of 30 tests were conducted. The data were analyzed for the severe slugging suppression of the surfactant and gas-lift combination, the effect of gas lift on surfactant injection, and the effect of the surfactant on the reduction of the gas-lift gas. The combination technique with the highest gas-lift rate completely eliminated the severe slugging for the all of the tests conducted. Surfactants were able to suppress severe slugging for most of the cases. The performance of "Only Surfactant Injection Case" increases as the gas-liquid ratio increases. For all of the tests, back-pressure reduction was observed. MEPI is used as the main parameter to assess the performance of the severe slugging suppression methods. Gas-lift not only contributes with density reduction through volumetric increase of gas in the riser but it also reduces the mixture density by promoting more foam generation. There were reductions in the gas-lift rate from the original maximum gas-lift injection rate for all the tests conducted with surfactant injection.
The Effect of Management Involvement on Vehicle Safety Improvement
Authors: Catten Corey , Johnson Casey 
Published: October 2014

Abstract
The importance of management involvement in any safety initiative is well understood in the industry. In our research, we discovered three necessary factors to maximize safe driving behavior with an invehicle monitor system: 1) real-time audible feedback of unsafe behavior in the vehicle, 2) an environment where the driver can change small unsafe choices for the safer without penalty, and 3) involvement by management or another interested third party to review the driving history and take action if necessary. Over the past several years, we observed varying degrees of management involvement leading to varying degrees of success in the safety improvement in the fleets we monitor. This paper quantifies the effect of the management involvement in terms of measured unsafe driving events.
The paper applies to HSE professionals and management working on land transportation safety programs based on the industry best practice for land transportation safety.
The paper shows that management attitudes alone dramatically affect the outcome of vehicle safety programs. Since vehicle-related accidents are the highest category of fatalities in oilfield work, the significance of this fact is lives… saved or lost.
Unique Interpretation of JT Heating Across Perforations to Interpret Near-Wellbore Skin - A Case Study
Authors: Justin Hayes , Joshi Nikhil 
Published: October 2014

Abstract
Surveillance and monitoring of pressure drop across completions is critical to any deepwater well that is completed with sand control. Maintaining acceptable velocity across the perforations and sand screens have been discussed to be critical and are derived from the knowledge of pressure drop across each entity. Conventional pressure transient analysis (PTA) which requires the well to be temporarily shut-in is the most applied methodology to calculate that pressure drop. In this paper, an alternate method is proposed that uses Joules-Thomson (JT) heating across the completions to estimate this pressure drop. The method is explored through a case study on a Gulf of Mexico subsea well. The results from the JT method match with results from PTA. The application of JT to determine pressure drop can not only offer continuous monitoring of a well but also provide insight on more challenging situations such as a commingled wellbore with production from two sands. This paper is a discussion of the methodology to use JT for pressure drop calculations across the completions.
Underreamer with Real-time Communications and Optimal Bit Design Achieves Successful Lateral Well Placement - A Case Study
Authors: Chiniwala Barzin , Radford Steven , Bacon Robert , Fuller Tom , Badru Ola 
Published: October 2014

Abstract
As long as underreamers have existed in the oil field, operators have wanted a clearer understanding of how these tools are operating in real time. A new integrated underreamer that provides real-time communication via the same mud pulse telemetry system as the familiar MWD/LWD/RSS (Measurement While Drilling/Logging While Drilling/Rotary Steerable System) tools and allows the placement of the underreamer closer to the bit (to aid vibration management and minimize rat hole length), has been used. This advanced underreamer system reveals the current condition of the tool and the position of the blades (implied hole caliper) to the operator, additionally, it uses internal hydraulic oil pumped-pressure activation (and deactivation) of the blades. This integrated underreamer was used to simultaneously drill and underream an 8½-in. × 9⅞-in. pilot hole section interval and then side-track to drill an 8½-in. × 9⅞-in. mainbore lateral section to the top reservoir horizon.
A case study in the UK North Sea Harding field is included as part of this paper describing the critical challenges of simultaneously drilling and underreaming a development well, including the equivalent circulating density (ECD) management within narrow pressure margins. Underreaming an 8½-in. × 9⅞-in. wellbore all the way to TD was viewed as the most acceptable method to manage ECD and be able to get the production liner to bottom. Other ECD control methods used on this well, and detailed in this paper, include a combination of adjustments of rate of penetration (ROP) and rotations per minute (RPM), drilling fluid rheology management and pumping of sweeps at different stages of drilling to aid hole cleaning. The PDC (polycrystalline diamond compact) bit design was matched to that of the reamer with a proprietary technology to optimize the drilling assembly and minimize stick-slip or coupled lateral vibrations.
The reaming system was used to drill and underream 6,645 ft. in two runs totalling 288 hours on-bottom drilling, with minimal vibrations. The well was drilled with an inclined trajectory of up to 90° with as much as 5°/100 ft. dog leg severity. The reamer appeared to provide an in-gauge borehole allowing for successful running, rotation and cementing of approximately 4,300 ft. of 7-5/8″ liner without any issues, demonstrating superior borehole quality.
This paper outlines the problems anticipated in this challenging well, the thinking behind the unusual reamer selection, the method for proper synchronization with the pilot bit, and the keys to overall success.
Correlations to Estimate Key Gas Condensate Properties through Field Measurement of Gas Condensate Ratio
Authors: Paredes J. E. , Perez R. , Perera L. M. , Larez C. J. 
Published: October 2014

Abstract
When a hydrocarbon reservoir is discovered it is important to know the type of fluids that are present as well as their main physicochemical characteristics, this is normally obtained by performing a PVT analysis to a representative fluid sample of the reservoir. In most cases, having a PVT analysis can take several months, which limits the number and type of reservoir studies that can be carried out during this period.
The only parameter that can be measured almost immediately after a well is completed, are conventional production measurements. In some cases this production measurement can be obtained before completing the well by using special testing or measuring equipment such as a DST (Drill Stem Test, acronym in English).
It is important to obtain preliminary values of properties such as: molar percentage of heptane and heavier components (% mole of C7+), molecular weight of the original fluid (MW), maximum retrograde condensation (MRC) and dew point pressure (Pd). Most of these properties are very important for exploitation of gas condensate reservoir and their early early availability will allow engineers to carry out reservoir studies that will ensure an efficient exploitation and maximize the final recovery of the liquids present in the reservoir.
This work proposes a series of correlations, obtained from analyses of several PVT studies collected mainly from reservoirs of Mexico and other regions of Latin America. These correlations can be used to estimate reservoir properties for gas condensate such as: % mole of C7+, MW, MRC, Pd and Z-factor at Pd.
The only parameter needed to use these correlations is the value of the gas condensate ratio (GCR) of the fluid during the early stage of production. These empirical equations should be valid for any gas condensate reservoir worldwide; although a range of usability is proposed for a better performance of the correlations.
Interpretation of Cleanup Data in Gas-Well Testing From Derived Rates
Authors: Hashmi G. M. , Kabir C. S. , Hasan A. R. 
Published: October 2014

Abstract
In drillstem testing (DST), analyses of transient data are generally restricted to the post-cleanup period because rates often go unmonitored at early times during the cleanup phase, unless aided by multiphase flow metering. The value of early-time production data monitoring may be overlooked for two reasons: first, transients may be difficult to interpret because of two-phase flow in the formation; second, two-phase flow metering becomes a requirement.
The objective of this study is two-fold: to estimate rate from distributed-temperature sensor (DTS) data available for downhole telemetry with a rigorous transient analytical model, and to use the computed rates to perform transient analysis for both the pre- and post-cleanup periods. Comparing and contrasting permeability estimates from the two periods provides guidance on the suitability of this approach. To that end, this study compares and contrasts rate computation with analytical methods. The new methods entail transient-temperature modeling with and without superposition effects. Two field examples strengthened the new rate-computation methods introduced here, and simulated examples probed the possibility of extracting meaningful information from the cleanup data.
Resolving the Mixed Salinity Challenges with a Methodology Developed from Pulsed Neutron Capture Gamma Ray Spectral Measurements
Authors: Ma S. Mark , Pfutzner Harold , Al-Hajari A. A. , Musharfi Nedhal M. , Saldungaray Pablo , Azam Hisham 
Published: October 2014

Abstract
The mixed-salinity environment poses a challenge in petrophysics. Many efforts have been made, but the industry still lacks a workable solution for accurate formation measurements in the presence of variable or unknown water salinity, especially in reservoir surveillance when well completion restrictions require running slim logging tools.
A pulsed-neutron (PN) spectroscopy tool was characterized using laboratory limestone formations and with data generated through Monte Carlo simulation. Seventy-six measurements were conducted with conditions of openhole (OH) and cased-hole (CH) completion, porosities of 15.4 and 42.9%, borehole fluids of water and oil, and borehole and formation water salinities of 0, 20, 50, 100, and 200 ppk. These were supplemented with 88 modeled points to better define the porosity (extending down to 0%) and salinity dependence of the tool response. Twenty additional measurements were taken in a dolomite formation to investigate lithology dependence and ten additional measurements were taken with oil in a 43.9% porosity formation to investigate fluid saturation dependence.
Salinity is derived from data obtained with a PN tool operated in the carbon/oxygen (C/O) mode. Ratios of the elemental yield of chlorine (Cl) to that of hydrogen (H) are computed from the near- and far-detector capture gamma-ray spectra. Using a scheme similar to C/O log interpretation for oil saturation, crossplots of the near- and far-detector Cl to H ratios were generated. A quadrilateral is formed on this crossplot by separately varying the borehole and formation water salinities. The established quadrilaterals, a newly developed algorithm to handle intermediate values of near and far ratios and of porosity, and independently obtained borehole water holdup (Yw) and reservoir water saturation (Sw) are then used to compute the borehole and formation water salinities that produced the measured Cl to H ratios.
Results obtained were compared with values determined from formation tester samples, demonstrating that a solution for accurate formation water salinity determination is established, thus resolving the challenge of mixed salinity in formation evaluation and reservoir surveillance.
Lease Fuel, Fuel Gas or Fuel Consumed in Operations- Is it Reserves?
Authors: Morales E. , Lee W. John 
Published: October 2014

Abstract
Lease fuel (also called fuel gas, fuel consumed in operations or lease-used gas) is defined by the SPE/WPC/AAPG/SEG/SPEE-Petroleum Resource Management System (SPE-PRMS) as "that portion of produced natural gas, crude oil, or condensate consumed as fuel in production and lease plant operations." Reporting this "fuel" as reserves, usually with a clear reference to the reserves attributed to these volumes, has been a practice commonly used by many companies, but not by all. Differences exist within a country and between countries regarding the application and interpretation of the existing standards and regulations concerning the reporting of lease fuel as reserves, resulting in a lack of consistency and comparability between oil and gas companies in the reserves externally disclosed.
Annual reports, 10-K and 20-F forms of oil and gas companies indicate that, during the last few years, significant volumes of additional reserves are still being added as a result of including, for the first time, the fuel Consumed in Operations (CiO) in the disclosed reserves. These volumes can be material.
Based on the companies reviewed, these volumes can represent up to 12% of the company's total proved reserves, depending on the amount of produced hydrocarbon products consumed as fuel, the type of processes used (e.g., normal production of oil and gas, LNG processing, electricity generation, compression needs, etc.) and the location of the terminal point (SEC terminology) or reference point (SPE-PRMS terminology).
A review of definitions, apparent misaligned standards (e.g., SPE-PRMS, Canadian Oil and Gas Evaluation Handbook (COGEH)) and requirements from regulatory bodies (Canadian Securities Administrators (CSA), US Securities and Exchange Commission (SEC), UK London Stock Exchange (LSE-AIM), European Securities and Market Authority (ESMA), Australian (ASX), Hong Kong (HKEx) and Singapore (SGX) Stock Exchanges) are discussed in this paper. Examples are also presented with the rationale of why these "lease fuel" volumes should be part of the reported reserves and should include proper narrative on these volumes. Updates of the lease fuel definition and references to lease fuel in the SPE-PRMS are also suggested in this paper, in order to reflect that, during the last few years, many countries and/or regulators have adopted the SPE-PRMS as the estimation and classification standard for reserves and resources, as well as the increasing amount of large integrated energy intensive projects (some of them presently in the undeveloped reserves category), and the increased relevance of unconventional resources and their role in lease fuel.
Inconsistencies in the approach to report (or not) the "lease fuel" as reserves are addressed, highlighting the need for clarity in the standards and disclosures being applied to ensure proper transparency, consistent valuation and reporting within the industry in the area of lease fuel, allowing proper comparability.