bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of an Ethoxylated Amine Surfactant for CO2-Foam Stability at High Salinity Conditions
Authors: Le Linh , Ramanathan Raja , Nasr-El-Din Hisham 
Published: November 2019

Abstract
CO2 flooding is well-known to be an effective EOR method and has been successfully implemented around the world. In heterogeneous formations, CO2 foam has been utilized to achieve conformance and mobility control. However, the foam performance degrades significantly at high saline environments. Ethoxylated amines have been reported to be successful in high pressure-high temperature (HPHT) conditions. This paper investigates the results obtained from a study of the foamability and foam stability at varying salinities, initial pH, and surfactant concentration.
The surfactant is evaluated to provide optimum concentration, salinity, and a pH level for better foam performance during EOR applications. Bottle shake tests achieved the objectives of this paper. Different salinities of brine, ranging from 0 to 25 wt%, mixed with the surfactant, with concentrations of 0.1 to 1 wt%, helped in the investigation of the foam performance. The bottle shake tests were conducted to prescreen the surfactant concentration, salinity, and pH level, at ambient conditions. Sodium chloride was used to prepare the solutions.
The bottle shake tests indicated that, in terms of foam half-life, the optimal surfactant concentration was 0.25 wt% for salinities of 0 to 15 wt% NaCl. Moreover, at this salinity range, the lowering of the surfactant solution's pH had a detrimental effect on the foam stability. The faster collapse of the foam at lower pH could be attributed to the repulsive interactions between the amine headgroups. The optimum initial pH was between 6 and 6.5 for salinity between 0 to 15 wt% NaCl. However, for higher salinity environment, 15 to 25 wt% NaCl, foam stability at low pH shows drastic improvement over its counterpart at lower salinities. At these high salinities, the optimal surfactant concentration was 0.50 wt%.
The application of the ethoxylated amine surfactant at different salinity levels has not been studied in detail. The application of this surfactant needs to be evaluated for optimum concentration, pH, and salinity. The effect of the surfactant's initial pH on the foamability and foam half-life has not been investigated. This paper addresses these gaps in literature and provides an optimized composition that can be applied for EOR operations.
A New, Low Cost CNG Ship, the Optimum
Authors: Fitzpatrick John , Stenning David 
Published: November 2019

Abstract
The quest to develop a low-cost, volume efficient CNG ship has been pursued for two decades. The optimum way to store compressed gas is to stack long lengths of hexagonal close-packed pipe horizontally in the holds of a ship. Past attempts to use this approach failed because as the ship flexes at sea, the pipes rub against each other which is clearly unacceptable. A novel technical solution has been developed and a ship design, based on this new "Optimum" technology, was recently Approved for Construction by the American Bureau of Shipping. This paper describes the technology, the ship, the design process and concludes with an economic evaluation.
By forcing long horizontal hexagonal stacked pipe tightly together within the hold of the ship the friction mobilized between the pipes creates sufficient shear resistance to prevent the pipes from moving and fretting in any circumstance. Based on this novel principle, a CNG ship with a capacity of 200 million standard cubic feet of natural gas was designed. The CNG-O-200 design was approved by the American Bureau of Shipping in January 2019 after three years of design, physical testing, computer modeling, and verification of safety and reliability. Some of the challenges addressed were: Determination of the forces and the mechanism needed to mobilize the friction,Design of the ship envelop, focusing on the midship section,The physical testing program to prove the system works,Developing a gas loading and discharge method was safe, simple and cost effective.
The main result of this work is a low-cost and volume efficient CNG ship that is Approved for Construction by ABS. On a volume equivalent basis, the size of a CNG Optimum ship is less than one-half the size of past CNG ship designs such as the Coselle CNG ship. This has significantly improved the economics of marine CNG shipping.
Marine CNG shipping has been an emerging technology and industry for many years with limited commercial success. Applications of marine CNG include markets that neither LNG nor pipelines have been able to serve, such as stranded offshore gas and smaller regional markets. This new low-cost and efficient CNG ship offers industry a new way to monetize stranded gas reserves and serve smaller regional gas markets.
Simplifying the Complex: Saturation Modelling in a Challenging Carbonate Reservoir with a Tilted Contact & Significant Imbibition in the Sultanate of Oman
Authors: Hadidi Shahab , Boya Ferrero Maria , Al Sadi Badar 
Published: November 2019

Abstract
The fluid fill concept of a complex carbonate reservoir of the Shuaiba Formation has been re-evaluated after 45 years of production. Structural changes post primary drainage resulted in a tilted contact towards the north east and water imbibition into the oil zone in a considerable volume of the reservoir. Rock facies change substantially vertically and laterally as observed from the 25+ cored wells and have camouflaged the fluid fill impact. Reservoir heterogeneity increases from the relatively homogeneous mud-dominated rock type in the central south-east to more heterogeneous grainstones and grain-dominated packstones further away. This paper demonstrates the value of using simplified and structured approaches to analyse saturation profiles to deduce possible fluid fill concept(s) and water saturation distribution.
The saturation profile with core permeability and core facies interpretation were used to identify imbibition, map the water table (imbibition) surface and recognize the trend of structural tilting post-charge. The central south-east area has negligible tilting and imbibition with a saturation model that could be simplified to primary drainage.
Above the water table, the mud-dominated rock saturation model was the reference point. Due to scarcity of wells unaffected by imbibition or tilt, a benchmark primary-drainage saturation model of analogue carbonate reservoirs was used to create a first-pass saturation model of the mud-dominated rock and identify entry height. The paleo-reference (original FWL) was reconstructed from the OWC picked from 72 vertical wells and smoothed by the general trend of tilt from the shallower seismic horizons. The workflow relied on using the mud-dominated rock saturation model to flag other rock types in uncored wells and possibly reducing the uncertainty in facies distribution. With the complexity at hand, difficulty in populating the facies between wells and time constraints, the water saturation below the water table was interpolated from all vertical wells.
The paleo-reference reconstruction indicates substantial tilting of the structure post-charge. One-third of the hydrocarbon volumes are in the imbibed region. The reservoir has been charged close to the irreducible water saturation and the majority of logged wells display paleo imbibed transition zones so it was not possible to utilize saturation-depth signature to identify a large number of distinctive rock types.
Due to the aforementioned, the saturation model for all of the reservoir rocks could be simplified by a single saturation function above the paleo-reference and a current water table depth.
Successful MPC Application for Ultra-Deepwater Well in South America: Case Study
Authors: Souza Leonardo , Sasso Alejandro de , Ribeiro Danilo , Guzman Jose 
Published: November 2019

Abstract
Exploration deepwater wells demand proper planning to mitigate any potential risks during well construction where uncertainty can play an important role. For this reason, designing dependable barriers under such a scenario requires innovative techniques, such as Managed Pressure Cementing (MPC). Using Managed Pressure Drilling (MPD), the operator can control the wellbore pressure while drilling each section. This unconventional solution for a short operational window has been successfully applied in some fields around the world, with additional advantages when cementing jobs are designed and executed.
The tight operational window expected for a 9-5/8-in. liner and the presence of gas were the main drivers to analyze the most likely scenarios for the cement job. The analysis describes that by managing the hydrostatic pressure of the fluids by applying pressure in the backside makes it possible to maintain control of the wellbore—without influxes or losses—before, during, and after the cement job. Nevertheless, to achieve the most reliable hydraulic modeling, critical parameters were identified for use as part of the input for a state-of-art cement simulator.
The scope of the cementing job for this case study was designed using a state-of-the-art simulation software to determine expected hydraulics outcomes. The main target was to maintain the bottomhole Equivalent Circulating Density (ECD) between 12.2 and 12.4 ppg during the entire cementing job operation. This 0.2-ppg margin was achieved by applying designed Surface Back Pressure (SBP) by using an MPC operational technique and finishing in a statically overbalanced condition. Dynamic pore-pressure and leak-off tests performed before the cement job confirmed the operating window. The information obtained was analyzed using appropriate software. This previous data was important to define appropriate fluids volumes and design to calculate the minimum SBP necessary for the safe execution of the job, always aiming to reduce chances of kicks and mitigate losses.
The cementing operation was performed according to the planned procedure, with no deviations, and the cementing job was performed in accord with the pumping schedule and SBP. Displacement was completed with zero mud losses, and lift pressure was observed as expected. MPC is a recommended method for zonal isolation in such cases as a small operational window, even more so when challenging deepwater scenarios are encountered. A case study of this cementing job is presented in this paper to discuss the planning process, details of the execution, and lessons learned.
Enhanced Well Remedial Decisions from Exact Location of Fluid Movement Behind Casing Identification
Authors: Croon Marcel , Huber Perry , Wright Jacob 
Published: November 2019

Abstract
Historically, acoustic wellbore monitoring is one of the main methods of detecting fluid movement behind the casing. Analysis of the complex acoustic environment in the wellbore can be challenging. A standard hydrophone noise tool is unable to measure flow directions (vertical and horizontal) and cannot detect low flow, low pressure sporadic events or multiple sources. This uncertainty may result in subjective acoustic interpretation leading to poor advice on remedial actions for wells with well integrity issues. A geophone array, including four 3-component geophones deployed via Wireline, provides a solution for this problem by creating a three-dimensional map of the acoustic environment. This acoustic profile, with accurately measured background noise levels throughout the length of the well, is then analyzed to confirm source locations and presence of flow (gas / oil / water) behind casing. The Unique geophone array configuration has allowed us to confirm source locations and flow paths of unwanted fluid flow for hundreds of conventional and unconventional production wells. Scenarios include wells with surface-casing or annular vent-flow issues, multiple source vent-flow situations, wells with cross flow between zones and integrity confirmation for gas storage caverns / zones. Since the detected flow is rendered into horizontal and vertical components, we can determine flow direction and accurately pin-point depth levels of fluid entry from the formation into the wellbore annulus. Geophone array noise logging has occurred in approximately 500 wells globally and the success rate for first attempt repairs is about 80% which is significantly higher than the typical 30% success rate.
Qualification of UNS N08028 and UNS N08825 Material as a Cost-Effective Solution for Extreme Sour Environment
Authors: Lamy Justine , Mizukami Akio , Millet Cécile , Néel Guillaume , Bouchart Nicolas 
Published: November 2019

Abstract
In recent years, Oil and Gas operators have faced new challenges with higher H2S partial pressure wells, especially in the Middle East. NACE MR 0175 part III provides guidance on the material selection for Corrosion Resistant Alloys; however, the well conditions considered by the Operator (total pressure 5526 psi, 1044 psi H2S, 279°F) are on the border of the UNS N08028 / UNS N08825 application domain, and therefore the recommendation would be to use a higher alloy, UNS N06985 material.
This paper describes a methodology to perform fine material selection for such critical conditions considering the representativeness of the testing condition and specific laboratory testing to qualify a suitable material for the intended application.
The objective was to evaluate the suitability of UNS N08028 and UNS N08825 material 110 ksi in the conditions described above. Based on actual reservoir conditions and fluid analysis, the test solution was defined to represent actual corrosiveness of the environment. Solution components, gas phases and in situ pH were defined using OLI® Stream Analyzer Thermodynamic software to reach the specified conditions at the test temperatures. Then, Stress Corrosion Cracking was assessed based on SSRT (Slow Strain Rate Test) as per NACE TM 0198-2016 [9], a rather conservative test as the material is stressed in its plastic domain; and C-ring as per NACE TM 0177-2016 [12], performed on rolled material to be representative of the final material surface finish.
All SSRT specimens showed a high ductility ratio and the absence of secondary cracking on the gauge section on both grades. All SCC C-ring specimens exposed to the environment successfully completed 720 hours exposure on both grades. Both UNS N08028 and UNS N08825 materials successfully passed the SSRT and C-ring tests, allowing the Operator to optimize the material selection by choosing a grade specifically qualified for their application and reducing the overall tubular cost by 30%.
Integration of Engineering Approaches and Workflows for an Economically Attractive Redevelopment of Highly Depleted Oil Rim Reservoirs - Giant Abu Dhabi Onshore Field
Authors: Meziani Said , Ghorayeb Kassem , Al Zaabi Najla , Hafez Hafez , Al Katheeri Abdulla , Maldonado Jorge , Khattak Iftikhar , Haryanto Elin , Chabernaud Thierry , Yersaiyn Saltanat , Kumar Sayani , Shahid Shawwal , Agam Abdelrahman , Shah Abdur Rahman , Chakraborty Subrata 
Published: November 2019

Abstract
This paper describes a pragmatic approach for reviving a highly depleted major Oil Rim Reservoir after more than 30 years of massive gas cap exploitation. The main objective is to assess options and identify the optimal plan to re-develop the Oil Rim while honoring and not jeopardizing the gas and condensate production of the network and the existing facility constraints.
An integrated workflow was designed and implemented to understand the reservoir geology, field production history and to address requirements of both oil rim and gas cap developments. Analysis started by a dynamic synthesis to track oil/water contact (OWC) and gas/oil contact evolution with time using available surveillance data: MDT pressure gradient analysis with petrophysical evaluation (RST & OH logs).
A study consisting of a comprehensive review and update of the static and dynamic models was carried out to ensure the model adequacy for robust re-development planning. The dynamic model quality was assessed by comparing dynamic model results with surveillance data especially with regard to predicting the contacts movements and pressure variation vs. time in the different regions of the Oil Rim.
Production forecasting and optimal re-development plan identification followed a systematic approach aiming at assessing the incremental impact on oil recovery through the utilization of artificial lifting, different types of wells and completion as well as a variety of water injection scenarios. Sensitivity analysis included horizontal well lengths, well density, well placement, water injection and production capacity as well as economic constraints.
Oil production from this low-pressure oil rim reservoir has been a challenge due to the spread oil resources and complicated production mechanisms. The movement of OWC and GOC has been very sensitive and caused unfavorable early water/gas breakthrough. Despite the low recovery factor, some attempts to revive dead oil wells through artificial lift means (ESP, booster pumps) were made and considered as an initial step to reactivate the inactive wells.
The low oil production volume and hence low recovery makes the oil rim re-development economically less attractive. However, integration of state-of-the-art engineering approaches, proposed innovative technical initiatives and new technologies create an opportunity for significantly more economically attractive re-development.
The workflows used and discussed in this paper were tested for four other oil rim reservoirs and can be implemented in similar challenging oil rim development projects.
An Effective Economic Approach for Confirming Bypassed OilWith the Use of a New Generation Slim Pulsed Neutron Logging Tool – A Field Case from the Gulf of Thailand
Authors: Vimolsubsin Pojana , Teeratananon Wirot , Chigbo Ikenna , Lerdsuwankij Thiti , Millot Pascal 
Published: November 2019

Abstract
This paper presents the successful application of a new-generation slim pulsed neutron logging tool for identification of bypassed oil in the Nong Yao field. The field comprises of different small pools of oil developed with horizontal wells. The wells are drilled with long lateral sections to increase the drainage area in an attempt to increase sweep efficiencies. However, the sweep efficiencies remained uncertain given reservoir heterogeneity and the nature of water encroachment into the wells.
Reservoir saturation monitoring through tubing is usually required for an effective reservoir management program in such a mature field, and a cost-effective method for future opportunity identification. The traditional slim pulsed neutron logging (PNL) tools often provided inconclusive results especially when deployed in complex completion conditions. A new-generation slim pulsed neutron logging tool, which provides high-resolution spectroscopy with a much-improved accuracy and precision was investigated and introduced. This tool delivers self-compensated sigma and neutron porosity measurements in a wide range of conditions, including complex completions and with varying amount of gas in the wellbore or annulus.
This new PNL tool was run in the Nong Yao field in December 2017 with the objective to prove the remaining oil at the top of a reservoir. The objective was to acquire data in GSH (sigma, fast neutron cross section, Porosity) and IC (spectroscopy) modes in 8-1/2" hole with conventional completion (7" casing + 2-7/8" tubing). Despite challenging borehole fluid conditions, the data acquired confirmed remaining oil in the reservoir and a new well drilled in 2018 targeting this bypassed oil is currently producing with very good oil production.
This successful implementation of PNL in 2017 led to the adoption of the tool as a good alternative for confirming bypassed oil in the Nong Yao field. This strategy has been adopted for well target validation and horizontal well placement to support the 2019-2020 infill drilling campaigns.
In December 2018, this tool was run again in three selected candidate wells to prove the remaining bypassed oil and oil saturation away from currently producing wells. The results acquired in all three cases showed clear oil/water contact movement and sweep where present, confirming sufficient remaining oil volume to justify the drilling of new infill wells to develop these volumes during the 2019-2020 infill drilling campaigns.
The new generation PNL tool provides a low-cost alternative for effective reservoir depletion monitoring. Proper reservoir management, additional opportunity identification, and infill drilling target optimization are all benefits that can accrue from accurately locating bypassed oil. Field development plans can then be further optimized, resulting in increased asset value.
Accurate Modeling of Relative Permeability Hysteresis in Water Alternating Gas Experiments
Authors: Aghabozorgi Shokoufeh , Sohrabi Mehran 
Published: November 2019

Abstract
The saturation history dependent relative permeability (kr) data have been reported frequently in the laboratory investigations. Accurate estimation of kr data with hysteresis effects is crucial, specifically in Water Alternating Gas (WAG) injection which involves a sequence of drainage and imbibition cycles. Although there are a few methods to model the hysteresis effects in three-phase systems, the predicted values are still not adequate to simulate the hysteresis observed in experiments.
In this study, a generalized three-phase hysteresis model was developed to simulate the observed hysteresis in the WAG experiments performed at Heriot-Watt University. It is discussed that the use of Land trapping coefficient in the hysteresis models is doubtful since it originates from the observed behaviour in two-phase systems which reach residual saturations. Hence, the new hysteresis model is developed based on innovative techniques to predict the oil and water saturation at the end of each injection cycle. Moreover, in the developed model, the formulations for estimation of hysteresis in water and gas kr data are updated to capture the observed behaviors in WAG experiments.
The suggested hysteresis model was evaluated by comparing the simulation results with the available experimental data. The results showed that the developed model is able to simulate oil, water and gas production more accurately. Based on the results, the model can simulate the pressure behaviours observed in the experiments with dominated hysteresis. In addition, the developed model can predict the oil, water and gas saturations at the end of each cycle with higher accuracy compared to the available methods in the literature.
The significant impacts of the hysteresis phenomenon on designing the best WAG injection scenario require a reliable hysteresis model for performing accurate reservoir simulations. The use of the suggested model elevates the accuracy of any feasibility analysis performed to evaluate the WAG injection scenario.