bluuebunny/crossref_metadata_2025_split huggingface dataset:
Microemulsion Additive to Mitigate Impacts of Acid Flow Back
Authors: Morales R. , Diaz C. 
Published: November 2017

Abstract
Interaction between organic/inorganic acid and crude oil, especially in the presence of free iron, might result in asphaltene precipitation and acid sludge formation, as well as fluid separation problems at the surface facility. These problems cause a decrease of well productivity and increase d operational cost. To mitigate the potential damage associated with acid stimulation to improve its performance, the following aspects need to be considered.

Methods, Procedures, Process
To identify the appropriate stimulation additives that ensure the performance of the acid job and prevent rigid film emulsion, a proper sludge evaluation is needed. The stimulation additives need to be miscible and compatible with different acid packages, need to have good affinity with the oil and water phases, high tolerance to the presence of free iron, and low contact angle to water-wet the formation for production improvement.
This paper addresses the required properties of stimulation additives in formulations for wells that produce low API gravity crude oil (less than 15 API), have downhole temperatures up to 150°C, and contain approximately 5000 ppm of free iron.
An extensive laboratory performance study including produced fluids compatibility, acid sludge tests at different oil and acid ratios, as well as iron content, were performed to identify suitable acid additives to minimize acid flow back problems in heavy oil fields. The impact of the acid flow back fluids with acid additives on fluid separation at surface facility conditions was also evaluated.
Identifying the most suitable and effective additives to prevent the acid sludge formation during the acid jobs and minimize the side effect of acid jobs on surface facilities, is presented in this paper, as well as the effect of microemulsion on this application and its effectiveness.
It is expected that results of this study will help the industry to minimize the downhole and surface problems associated with flow back in acid jobs.
Taking Drilling Operations Optimization to New Heights
Authors: Moustafa Islam khaled , Hammadi Majid Al , Rheaume Gregory , Ali Salim Al , Jaorawala Ammar , Mefleh Issam Rezek , Helali Osama Al , Salam Mohamed Abdel , Akl Bassam 
Published: November 2017

Abstract

Field Background
In Aug. 2015, Umm Lulu drilling team drilled and completed well014 as a first linerless design by setting the 9 5/8" casing in Thamama-I formation and drilling an 8 ½" section till TD, relying on swell packer for zonal isolation.
Post evaluation of UL-14 design found cross flow between Thamama-I formation and Thamama-II target reservoir.
The drilling division developed another design by extending drilling the 12 ¼" hole till Thamama-I A base to isolate Thamama-I with cement after running the 9 5/8" casing and drilling 8 ½" hole till section TD. This scenario was not possible to execute due to the unavailability of completion equipment (4 ½" × 8 ½" swell packer).
The drilling division thought out of the box to drill 6" hole directly from 9 5/8 casing to address the equipment availability constraint. This option was pursued after thorough evaluation of all potential challenges.
In April 2017, well018, which was a first revised design, was drilled and completed successfully 10 days ahead of plan, saving $2.00M.
In June 2017, well020 was delivered with the best jack up 10k duration in ADMA-OPCO (31.5 days) and the best single oil producer with lower completion duration of 56 days, saving more than 15 days and $3.2M.
Changing Perspectives of Cathodic Protection System for Above Ground Storage Tanks
Authors: Hanif Ateeq. Ur-Rehman , Busaeedi A. M. 
Published: November 2017

Abstract
A Cathodic Protection system can provide effective corrosion control against external corrosion threats to above-ground storage tanks; be it related to tank construction materials, coating degradation over operational life span or environmental corrosion caused by tank foundation, soil etc. Traditionally, several different types of anode installation schemes were practiced for current distribution to the tank bottom. These were ‘Horizontal or vertical’ anode installation distributed around the tank periphery or angular drilled anode installation to extend the anodes toward center of the tank bottom. Deep-well anode systems with multiple anodes in a single long bore-hole at relatively remote location were also used to provide common cathodic protection system for multiple tanks in tank farm area. These conventional anode-beds were easy to install, monitor and maintained. For safety and environmental reasons in new storage tank construction, an impermeable plastic membrane is now required to be laid under the tank to contain any corrosion leak if it happens. The use of a membrane beneath the tank bottom as secondary containment and as a means of leak detection thwarts any attempt of conventional anode-bed outside the tank periphery to be effective. The anode-bed and references electrodes or other monitoring systems are therefore installed within the space available between the membrane and the tank bottom during construction of the tank, as retro-fitting of anodes during operational service life would not work because of the inaccessibility below the tank bottom. A robust design of the cathodic protection system for a tank bottom is therefore imperative to ensure intended design life.
This paper briefly discusses the changing perspectives of the cathodic protection system from conventional anode-beds to a grid system showing the detail design approach adopted and highlights the implications of miss-design based on a practical example of a newly constructed 100 meter dia crude oil storage tank with 40 years design life if relevant design considerations are not addressed.
Successful Use of Downhole Camera Technology to Assist Fishing Operation
Authors: Al-Hajri Nasser M. , Al-Quwaisim Hussain A. , Al-Zahrani Rashad M. 
Published: November 2017

Abstract
Fishing operations are complex and time consuming. This is due to the associated uncertainty with the orientation and condition of the tool that requires fishing. In this paper, a case study is presented which demonstrates the usefulness of utilizing downhole camera technology in conjunction with fishing operations. The use of real time camera inspection enabled successful fishing of a challenging plug. In addition, the traditional trial and error approach used in most fishing operations was avoided reducing the operation time and cost.
The paper case study is a high pressure oil producer that has a stuck retrievable plug at 200 ft. The presence of the fish at a shallow depth makes well intervention operations critical from well control perspectives. In such cases, fishing operations must be meticulously designed to account and plan for contingencies should complications arise during fishing. Attempts to fish the plug using normal and heavy duty slickline were not successful. During these fishing attempts, several tools were lost in hole due to the damaged nature of the stuck plug adding to the complexity of the fishing operation.
To address this challenge, a downhole camera with real time data transmission capability was run in the well using coiled tubing to enable viewing the condition and orientation of the lost fishing tools and the stuck plug. The results of the camera inspection runs were instrumental in subsequent fishing tools selection and adjusting the operating procedures. The first camera run revealed the presence of metal objects obstructing proper latch to the fish neck. Following clean-up runs with magnet, the second camera inspection run clearly showed partial damage to the top of fish neck (chipped out metal piece). The rest of the fishneck was found intact.
Given the nature of damage to the top of the fishneck, conventional fishing tool sizes (3 in.) were not able to latch the fish. Accordingly, a smaller fishing tool (1.26 in. spear) was run and latched inside the bottom of the fish neck instead of the damaged top. The 1.26 in. spear run was successful in latching inside the fishneck and in recovering the fish safely. The fishing operation design, job execution, and contingencies will all be discussed in this paper.
Integrated Data Analysis Reveals the Presence of Sealed Fractures in a Large Tight Gas Field
Authors: Zadjali Faris Al , Saroj Vikram Singh , Calvert Stephen , Djermouni Karima , Hattali Ahmed Al , Rawahi Mohamed Al , Noirot Jean-Christophe , Kharusi Dawood Al 
Published: November 2017

Abstract
One of the largest gas fields in the Sultanate of Oman was developed between 2010 and 2016 by drilling 26 vertical wells for commingled production from three deep tight gas sandstone stacked reservoirs. The shallower reservoir is a rich gas condensate reservoir, while the other two contain lean gas fluids.
Over the last few years, the wells performance has been poorer than anticipated. An integrated study was carried out in 2016-2017 to identify the root causes of this under performance and eventually address it in a new field development plan. All subsurface and surface disciplines worked together analyzing available data in order to understand the production behaviour and complex nature of the field.
One of the major findings of the integrated study was the interpreted presence of sub-seismic lineaments corresponding to possible zones of quartz sealed fractures. This was supported by seismic, core, reservoir pressure (MDT) and pressure build up data. The integrated data analysis revealed that these lineaments are having a direct impact on the field performance, as the hydrocarbon in-place volume seen by each well is dependent on the compartments defined by these lineament boundaries. A large set of lineaments were added to the dynamic model after mapping from detailed seismic work. This addition resulted in very good matches of historical production and pressure data. These updates to the reservoir model will ensure a more accurate field forecast and provide a better field development strategy.
This paper will demonstrate that the presence of sealed sub-seismic fractures that may remain undetected can have a substantial impact on the performance of tight gas reservoirs. By identifying these sub-seismic elements and understanding their impact through an integrated approach, field performance can be better forecasted in order to account for the presence of these features.
Resolving Water Saturation Uncertainty in a Thin Oil Rim Reservoir, Using Sigma While Drilling, Case Study from Onshore Abu Dhabi
Authors: Syofyan Syofvas , Latief A. I. , Amoudi M. A. , Al-Arfi S. A. , Al-Shabibi T. A. , Dasgupta Suvodip , Qleibo Meretta , Gzara Kais 
Published: November 2017

Abstract

Objectives
This study focuses on resolving the water saturation (Sw) uncertainty in a small oil rim that consist of thin high-permeability layers (super K). Resistivity-based water saturation techniques suffer from multiple uncertainties including thin layers with distinct capillarity profile, inaccurate resistivity due to high-angle bed effects and unknown Archie parameters. Accurate saturation using alternate methods than resistivity based is critical for the calibration of saturation height model for reserve estimate and to design the perforation program away from the mobile water zone.

Methods
To resolve the issue of accurate Sw, an alternate method of computing saturation from sigma measurements while drilling is being investigated. Data from multiple wells has been analyzed- saturation from sigma being computed and compared to resistivity based saturation. The resulting saturation is benchmarked against other known sources of saturation like core data and cased-hole measurements. The input parameters used to compute the sigma-based saturation were validated by well test and PVT lab data.

Observations
A general assumption for LWD logs is that invasion is so shallow that LWD data acquired during drilling may be sufficient to evaluate uninvaded zone properties However, this premise need to be confirmed by other sources of information, in this case Multi-Depth of Investigation (MDOI) sigma data. It provides valuable insight into the status of formation invasion, at the time of acquiring data and of measurement quality control. In situations where the resistivity data does not suffer from any high-angle bed effects, there is immense value in combining the information from resistivity and sigma. When there are two measurements free from invasion and reading the same volume of rock, this can be used for not only calculating water saturations but also to fine-tune the Archie parameters, which might be of immense value in situations, for use on offset wells with resistivity data only.

Novel Information
Sigma while drilling is another weapon in the arsenal of the petrophysicist and the multi-depth of investigation sigma measurements in a LWD environment contributes a new opportunity to evaluate fluid saturations in reservoirs with unknown or variable Archie parameters.
Automated Well Test Analysis Utilizing Self-Adaptive Differential Evolution Method
Authors: Moussa T. M. , Alloush R. M. , Issaka M. B. 
Published: November 2017

Abstract
Well testing is the analysis of pressure and rate data from a reservoir to estimate the reservoir parameters. It enables monitoring and optimization of reservoir performance, and helps estimating the petrophysical properties of the reservoir. Nonlinear regression was presented to well test analysis more than three decades ago, and rapidly became the typical practice in the industry since then. Despite its popularity, the nonlinear regression technique received limited development, and still has major problems in well test analysis. In nonlinear regression, wrong initial guess of regression parameters could lead to incorrect results; as the regression algorithm might not converge to the exact results when the initial parameters' estimations are far from the actual values. This is mainly due to the convergence of some algorithms, such as Levenberg–Marquardt's algorithm, to a local minimum and missing the global minimum of the objective function.
The objective of this research is to develop a well test analysis technique utilizing Self-adaptive Differential Evolution (SaDE) algorithm, this technique can perform automatic reservoir parameters estimation using the pressure and its derivative responses for different reservoir models. The proposed approach is applied on different reservoir models, namely; radial flow in a radial composite reservoir model and radial flow in a circular homogeneous reservoir model. The performance of the developed method is analyzed and compared with Levenberg–Marquardt's algorithm. Sensitivity analysis is introduced to study the effect of different model parameters such as; wellbore storage, skin, mobility ratio, etc.
The obtained results showed that the developed well test analysis technique, using SaDE optimization algorithm, can be used to estimate the reservoir parameters with higher accuracy compared to Levenberg–Marquardt's algorithm. Unlike Levenberg–Marquardt's algorithm, the introduced well test analysis technique has less dependency on the initial estimate of parameters, and the overall regression performance is significantly enhanced. Furthermore, for automated interpretation in which the model is already known, this method allows the elimination of the initial guess-determination step.
This is the first time SaDE algorithm is implemented and applied to estimate reservoir parameters in well test analysis. Therefore, it is a step forward to, fully automate well test analysis and interpretation, where the need of initial estimate of regression parameters is eliminated. This achievement is not possible using conventional gradient-based algorithms such as Levenberg–Marquardt. Outcomes of this study would help well testing engineers and analysts to have better understanding of reservoir parameters and performance without initial guess-determination step.
A Novel Displacement Mechanism of CO2-Assisted Steam Flooding for Highly Acidic Heavy Oil Reservoir: An Experimental Study
Authors: Li Yi-Bo , Gao Hao , Pu Wan-Fen , Yang Liu , Dong Hong , Zhang Xiang , Wu Runnan , Li Qingzhi 
Published: November 2017

Abstract
The steam injection is an effective way to development heavy oil reservoir. But for the high acidic heavy oil, due to the high amount of naphthenic acid, the steam and heavy oil can easily form W/O emulsion which possesses higher viscosity and lower temperature sensitivity than crude oil and increase the displacement difficulty. The introduction of high pressure carbon dioxide was able to destroy the W/O emulsion structure and decrease the viscosity of formation fluid. In this paper, based on the NS block reservoir condition, the physical simulation experiments were carried to investigated the demulsification of CO2 in the displacement process. The results showed that The high acidic heavy oil of NS block can be formed the W/O emulsion easily during the steam flooding process and the high viscosity of emulsion increased the difficulty of displacement. In the flooding process, the high pressure CO2 possessed the demulsification function for the emulsion and thus the lower viscosity of oil can lead to higher cumulative recovery. The alternative injection measures achieved the highest recovery and appropriate CO2/steam volume ratio is very important to the following flooding. The temperature of steam had the biggest influence on the final recovery. The demulsification effect of high pressure carbon dioxide has never been considered as the mechanism of displacement. For highly acidic heavy oil, if the generated emulsion was able to be demulsification by carbon dioxide during the flooding process, it will become one more advantage for carbon dioxide as the important displacing medium in EOR area.
An Industrial Hygiene Study in Support of a Sustainability Initiative: Clean Air for All
Authors: Simmons R. J. , Rodrigues C. C. , Stephen S. , Al Maflahi M. A. , Yousuf R. Y. 
Published: November 2017

Abstract
This paper presents the results of an industrial hygiene study that confirmed the effectiveness of an active system in reducing the potential for employee, as well as public, exposure to benzene vapor. ADNOC Distribution has introduced an advanced vapor recovery system in some of its petrol stations, which is better known as a Vapor Recovery Unit (VRU) System. This system promises a reduction in the volatile organic compound concentrations in the ambient air in the stations, which are linked with the stations’ operations. These volatile organic compounds may cause health issues for both long and short term exposures. This study is conducted to confirm the validity and the benefits of implementing the VRU system in compared to petrol dispensing without VRU. The project was commissioned on two stations, one that was equipped with a VRU system while the other was not. Air sampling using 3M Organic Vapor Monitors™ (OVM), followed by desorption with carbon disulfide and analysis via GC-FID was conducted during May-June 2016. Sampling was conducted on two employees per 8-hour shift per station over two 24-hour cycles (total of 24 samples). Blank samples (one per shift) were also collected and analyzed with the actual samples. Meteorological data were obtained from Al Bateen Executive Airport during the sampling periods. While all of the results showed benzene exposures that were within UAE regulatory limits, a few samples from the non-VRU-equipped station showed exposures that were above the most stringent international guideline, the NIOSH Recommended Exposure Limit (REL). The data clearly encourage the roll-out of the VRU system in all of ADNOC petrol stations. Results were found to be promising; more than 58% of the samples from the VRU station did not contain any detectible concentrations of benzene, as compared to none of the non-VRU stations’ samples. This validates the purpose of the VRU system and hence, the study confirms the benefits of implementing the system from an HSE perspective, as it assures the Company’s workers a healthier and a safer working environment, and also supports the implementation of self-service petrol stations in the UAE, by reducing public concern about hydrocarbon exposure during petrol dispensing.
Multiple Key Operational Achievements Yield Major Economic Impact as a Result of Successfully Controlling Fluid Losses in Troublesome Zones of Jurassic to Permian Age in Offshore United Arab Emirates
Authors: Habsi Medhat Al , Bijjani Patrick , Dawson Graeme , McCurdy Paul , Anez Marcos , Luyster Mark , Tresco Kim , Dobson James W. 
Published: November 2017

Abstract
Two optimized polymer/borate/salt (PBS) fluid loss systems were recently implemented in two different ADNOC Sole Risk (ASR) wells while drilling different troublesome formations in the Arabian Gulf which are prone to losses. The first well (Well A) was drilled through the fractured Upper Khuff Formation, and the second well (Well B) through porous Arabs and fractured Diyab/Jubaila groups. The application of the PBS systems enabled the rigs to regain circulation and successfully drill to the total planned depth with less non-productive time attributed to curing losses.
The wells involved several different key objectives; however, zonal isolation and logging were critical to both. In addition, the ability to control losses, even at an acceptable rate for one of the wells, allowed the team to proceed with the critical logging program. If not mitigated, losses could have resulted in a well-control situation.
Controlling the losses on Well A allowed the first unimpeded logging suite, including high quality imaging, pressure sampling and avoidance of a liner run. After logging the section, drilling was resumed to the planned section total depth, and the liner was run and cemented successfully.
The application of the PBS system in Well B allowed multiple troublesome formations (Arabs/Diyab/Jubaila/Gulailah/Sudair) to be drilled as one interval and successful isolation of these zones. The losses were completely cured after applying this system in the correct zone. The total planned depth was attained and the casing landed and cemented.
The solution for these loss-circulation challenges when drilling was the development of a faster, as well as flexible, setting and crosslinking PBS system that could effectively bridge and/or adhere to the formation rock. The optimization also included extending thermal stability of the set plug to maintain a workable loss rate at the anticipated elevated temperatures and simulations to ensure the system would agglomerate and adhere to the limestone/dolomite rocks. Pre-planning started nine months prior to drilling these wells. The predicted challenges ranged from managing losses to developing contingencies for total loss of circulation through the above-mentioned formations. Contingency systems were devised using a decision tree and rig instructions were prepared for every wellbore/scenario. The planning process included determination of a pumpable volume that would facilitate spotting this fluid loss system only once.
This paper outlines the successes achieved in curing loss circulation in the 8⅜-inch section of Well A within the Khuff formation and the 12¼-inch section of Well B within the Diyab group formation. These were drilled in ASR Arabian Gulf region as shown in Fig. 1. Figure 1Location of the ASR wells in the Arabian Gulf.