bluuebunny/crossref_metadata_2025_split huggingface dataset:
Solving Field Produced Water Challenges with a Novel Guar-Based System: A Comprehensive Review of Actual Field Examples and Cost Savings Analysis
Authors: Ruyle Branden , Fragachan Francisco E 
Published: November 2015

Abstract
During fracturing operations, conventional and unconventional wells require from 50,000 to more than 200,000 barrels of water per well, which generates a strain on fresh water supplies. In areas where fresh water is scarce, water quality is not consistent, or delivering water to a location is logistically complex, the strain intensifies. Therefore, having capabilities to reuse produced or flowback water for fracturing applications is a cost-attractive option, especially when major savings in produced water disposal costs and reduced treatment requirements are achievable.
This paper summarizes the proven benefits of using a bi-polymer crosslinking system in environments where water quality cannot be guaranteed. In addition to the cost advantages of using a crosslink system that uses a conventional gelling agent, this paper also demonstrates the yielded cost savings per well that are achievable when reusing 100% produced and or flowback water for hydraulic fracturing operations. Produced water typically contains large amounts of dissolved monovalent and divalent salts and other types of ions. Some of the ions present in produced water interfere in the formulation of traditional crosslinking fracturing fluids and therefore create a need in certain systems to mix produced with fresh water in specific percentages. The guar-based system discussed in this paper allows for 100% produced water reuse without filtering or treatment, which is a major environmental breakthrough in fresh water preservation. The new fluid system consists of a specially formulated bio-polymer crosslinking system that is not affected by produced or inconsistent water quality typically associated with fracturing applications.
The fracturing fluid system can tolerate 100% untreated produced or flowback water with salt concentration in excess of 300,000 parts per million (ppm), between 5,000 and 30,000 ppm of divalent ions, and more than 400 ppm of boron and 185,000 ppm of chlorides. The thermal stability of the system is proven to be unaffected by bottomhole temperatures ranging from 120°F to 300°F. Rheological profiles illustrate that the fracturing fluid system yields higher viscosities compared to an equivalent, traditional borate crosslink fluid system in fresh water. Well treatment results indicate that the bi-polymer system can be accelerated or delayed with proppant-carrying/suspending properties comparable to those of a traditional crosslink system. Permeability tests demonstrate the non-damaging nature of the new system and actual field data demonstrates enhanced scale tendency reduction.
In summary, this paper comprehensively reviews the benefit of using a robust fracturing fluid that can use 100% produced water or flowback instead of fresh water for fracturing operations. The paper indicates that use of produced water or flowback for fracturing should become the norm as we move into a more environmentally friendly paradigm.
Particle Size Distribution in Casing While Drilling: A Quantitative Analysis
Authors: Velmurugan Naveen , Mathur Prakhar , Babu Vinay 
Published: November 2015

Abstract
In order to address various wellbore challenges, there has been improvements in methods of drilling and other wellbore activities since a long time. While the industry focuses on improvements of different methods, reducing Non Productive Time (NPT) has also become of great interest. Amongst many, one method to address the problem of drilling through fluid loss zone and to minimize casing running time and other NPT is Casing While Drilling (CwD). It is a method of drilling in which the conventional drill pipes are replces by the casing itself. During implementation of this method, there have been several observations of enhanced wellbore strength, pressure containment, better fluid loss control, etc. Plastering effect is considered to be the factor behind this, where the fine drill cuttings physically collide with the wellbore to form a stable mud cake layer that provides additional wellbore strength. Though plethora of work has been carried out, exact phenomenon of plastering effect is uncertain. Particle Size Distribution (PSD) of the drill cuttings along the wellbore is noted to play a crucial role is proper plastering effect. Authors of this paper, attempt to quantify the PSD in CwD that takes place during plastering effect. The work is expected to help in understanding the crushing effect and the background of fluid loss prevention.
An Environmentally Benign Catalytic Process Enhances in Situ the Quality of Gasoline
Authors: Kokkinos Nikolaos C. , Mitropoulos Athanassios C. , Nikolaou Nikolaos A. 
Published: November 2015

Abstract
In the present research work an in situ conversion process of light-light cracked naphtha (LLCN) to strong anti-knocking mixtures is proposed as a potential solution to the serious drawbacks from the use of gasoline ether oxygenates (MTBE, ETBE, TAME) from the refineries.
Aqueous biphasic Rh/TPPTS-catalysed hydroformylation reaction of olefins present in a Greek refinery naphtha cut comprises the first part of the two-step proposed process. The second part of the proposed LLCN upgrade process is the in situ hydrogenation of the produced aldehydes to the corresponding alcohols catalysed by Ru/TPPTS complex in aqueous media. Both catalytic systems of Rh/TPPTS and Ru/TPPTS were revealed as effective catalytic systems for biphasic hydroformylation and biphasic hydrogenation of complicated mixtures, respectively. The effect of the pressure, temperature and time of the reactions, as well as the influence of the L/Me molar ratio were investigated.
In the first step (hydroformylation reaction) as well as in the second step (hydrogenation reaction) the highest conversion of more than 95% of the olefins and aldehydes respectively was observed at mild conditions, at a short reaction time. The upgraded LLCN could potentially replace the harmful gasoline ether oxygenates from the refinery blended gasoline pools with an in situ and an environmentally friendly catalytic process. Therefore, the ultimate fuel will contain more oxygen, due to the producing favourable strong anti-knocking alcohol mixtures; it will have better combustion properties and bigger octane numbers.
Application of Enzyme EOR in a Mature UAE Offshore Carbonate Oil Field
Authors: Jabbar Muhammad , Azrak Omar , Berthier Maxime , Blondeau Christophe , Al-Amrie Omar 
Published: November 2015

Abstract
Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. One of the main oil producing reservoirs of Jurassic age has been the subject of a number of EOR studies at lab and field scale to achieve a higher ultimate recovery factor.
In 1991, TABK initiated its first gas injection EOR Pilot with full-field expansion in 1997. In 2014 a successful Chemical EOR Pilot was carried out that showed a significant drop in residual oil saturation around the target well. As all the pumping equipment was available for the Chemical EOR project a window of opportunity opened up at short notice to perform a second EOR test on other wells.
The literature has recently highlighted successful applications of a relatively cheap commercially available enzyme in mature oil wells around the world with no environmental impact. This would be the first Enzyme EOR application in the Middle Eastern carbonates and, if successful, could provide a logistically simple, cheap method for enhancing oil recovery and assist Abu Dhabi to achieve its objective of 70% recovery factors.
Although there had been no time to evaluate the product in Total’s labs it was decided to go ahead with the test anyway in the spirit of supporting ADNOC’s initiative to accelerate the application of emerging technologies. This paper discusses the design, reservoir monitoring and lessons learnt from a "Huff-n- Puff" application of Enzyme EOR.
In terms of operations, the campaign was completed successfully; it demonstrated that the application poses no risk of flow assurance or to the environment and has provided invaluable experience of incorporating an EOR Pilot in day-to-day operations. In terms of EOR effect, an increase in oil rate is observed in only one well with no significant decrease in the water cut; in addition, the increase could be equally explained by well stimulation and/or better well stability (less slugging).
24 years of successful EOR through Immiscible Tertiary Gas Injection
Authors: Madathil Asok , Azrak Omar , Pearce Adrian , Al Amrie Omar , Gunasan Erkan , Blondeau Christophe 
Published: November 2015

Abstract
Total has been operating oil and gas production from a series of heterogeneous reservoirs offshore Abu Dhabi since 1974. Today's world class recovery factor is due to early application of new technologies such as ESPs, gas lift, multi-lateral wells, field-wide tracer and state-of-the art reservoir monitoring and well management. But the main contributor to this high recovery factor is the application of EOR through Immiscible Tertiary Gas Injection since as early as 1991 in 2 of the main reservoirs, it resulted in a recovery factor of over 50% in one of the main reservoir; a top class achievement for a carbonate reservoir and it is still contributing to more than 15% of today's field production.
After 17 years of production, the water cut reached almost 90% in one of the main reservoir. It was imperative to improve oil mobility and recovery in the reservoir to guarantee long term production. Of the various EOR methods considered, injection of natural gas was found to be the most technically and commercially viable. Several laboratory experiments and simulation studies have been performed to confirm the benefit of gas injection. Then, 2 successful pilots in 1991 and 1993 resulted in the decision to develop the technique on a full field configuration.
The Tertiary Gas Injection has been developed on the 2 main reservoirs of the field. These 2 reservoirs have comparable OOIP but very different properties and configuration. One reservoir is 160m thick with good vertical communication and has pressure support by an active bottom aquifer. The second reservoir has 14 thin layers; each layer is 3 to 20m thick and is separated from each other by anhydrite layers with no aquifer support.
This paper will describe the practical experience of immiscible Tertiary gas injection, present the results after 24 years of injection and analyze the possible reasons for differences in performance between the wells and reservoirs. In addition, it will describe how today's strong reservoir management, integrating surface constraints, helps to optimize the production leading to a constant level of production over the past 4 years; which, for a mature oil field that normally declines at 10–15% per year, represents a great achievement.
DAS Acquisition In A Matured Field During 4D: A Challenging Initiative With Multiple Objectives
Authors: Sanghvi G. , Le-Roch J. F. , Fernagu J. , Elazabi S. , Al-Naimi A. , Parker T. , Dathan S. , Toguem E. , Lemetayer p. , Allanic Ch. 
Published: November 2015

Abstract
A complex carbonate oil reservoir off the coast of Qatar has been under production since 1997. The field development is based on horizontal oil producers, water injectors and the use of Electrical Submersible Pumps (ESP) as the artificial lift method. A full field 4D seismic data acquisition was undertaken in 2014 to support the future development phases. A Distributed Acoustic Sensing (DAS) acquisition was included in the 4D seismic program to capture a Vertical Seismic Profile and observe the fluid flow dynamics inside the well bore together with the reservoir inflow. The dynamics of gas fraction was imaged through a tuned operating sequence of the well. A digital movie was captured for each location in the wellbore from toe to pump intake.
The first of its kind sonic data capture involved a DAS system using fiber optics. Thanks to a permanent fiber optic into the well, the simultaneous captures of DAS system reduce the incremental cost for the DAS information.
Gas locking in the ESP is the major cause of down time and reduced ESP run life. The selected well is in an area with limited water drive. The high cost of replacing failed ESPs affects the economic limit of the well and thus reduces the recoverable oil.
The applied operational sequence successfully observed intermittent ingestion of gassy fluids into the ESP intake. This provided key information to diagnose the root cause of gas-lock.
The incident free operation has clearly imaged (filmed) the fluid dynamics of gas and liquids interacting with the ES pump intake.
How detailed the challenges of preparing and conducting this operation were overcome is described. The operational field constraints cover safety, weather constraints, unmanned well platforms, the effects of streamer shooting and simultaneous production operations. On-shore details are described in relation to unusual job planning requirements including logistics and statutory requirements.
The results show DAS images that identify the specific gas volumetric fraction of fluids all along the well and entering the pump intake. The acquisition program fully captured the development and movement of large gas bubbles towards the ESP and which subsequently develop into a gas-lock event. The sensing includes images from the drain toe, to ESP intake and onto the well head. The acquired data shows the root causes of operational difficulties particularly during an ESP restart. One can see the actual gas handling performance of the ESP system as the specific gas volume fraction at ESP intake evolves over time.
The full sequence of this DAS advanced application has fully captured a gas lock event. This brings key information to improve ESP performance in a gassy environment from the completion design and operating points of view.
Synthetic Analysis of Full-Waveform Crosshole Seismic Toward CO2EOR Monitoring in Abu Dhabi
Authors: Nakamura Yuki , Takanashi Mamoru , Elila Abusaa 
Published: November 2015

Abstract
This study aims at designing optimal crosshole seismic approach for CO2EOR (enhance oil recovery by CO2 injection) monitoring in Abu Dhabi. It is not easy to perform successful reservoir monitoring for carbonate reservoirs in the Middle East because rock properties may not change much associated with fluid replacement. We investigate advantage of newly available elastic full waveform inversion (FWI) for detection of CO2 flooded zones. To investigate advantage, applicability and future problem of time-lapse FWI for CO2EOR monitoring, we conducted rock physics study, elastic seismic simulation, and test application of FWI to synthetic data.
We first made realistic velocity models based on Gassmann's equation and actual well logs obtained before and after CO2 injection at carbonate reservoirs in Abu Dhabi. The in-situ light oil at the target reservoirs was replaced by CO2 (Secondary mode CO2EOR). We prepared models with different width and thickness of CO2 flooded zones and analyzed detectability of seismic waveform change. We also conducted test application of elastic full waveform inversion to synthetic data for delineation of CO2 flooded zones.
Results of the rock physics study show 1.6% decrease in P-wave velocity, little change in S-wave velocity and density associated with secondary mode CO2EOR. The small property changes are caused by the rigid rock frame and small density difference in light oil and supercritical CO2 at the reservoir condition.
Next we performed synthetic seismic analysis based on the rock property models, available crosshole seismic source and realistic well distances. Because of the small property change, seismic traveltime difference and waveform change are quite small when well distance is 116ft. When well distance is 700 ft or greater, guided waves, or trapped energy inside low velocity layers can be observed; relatively large waveform change can be observed in the guided waves due to CO2 injection. Although guided waves have not been used for reservoir monitoring, they are sensitive to small Vp and thus can be an indicator of the CO2 flooding.
The elastic FWI result for a model with well distance of 1160 ft demonstrated good representation of the differential Vp with vertical resolution of 20-30 ft and some horizontal resolution. Although we need further investigation on repeatability and signal transmittability using actual field data, our synthetic study indicates possibility of identifying layers with CO2 using guided waves and elastic FWI.
Hard Formation Durability Gains 14% Footage and Replaces 2.7 Bits Versus Offsets
Authors: Cuillier Bruno , Mangeny Aurelien , Jelly John , Ballard Brian 
Published: November 2015

Abstract
A specially designed diamond impregnated bit set new performance records in its initial application in a hard, abrasive Oman formation. Built for turbine drilling in the formation's sandstone-siltstones-shale, the 212.72-mm (8 3/8-in) bit drilled 588 m (1929 ft) in a single run, increasing footage drilled by 14% compared to the previous-best 8 3/8-in. run with a ROP of 2.02 m/hr (6.6 ft/hr). This performance replaced 2.7 bits through increased footage drilled and drill out capabilities. When the bit was pulled due to the BHA it was dull-graded: 3-2-WT-A-X-1-LM-BHA.
The bit developed for the Oman run was a matrix body with 16 blades. Maximum durability and performance in the high-compressive strength formation was addressed with diamond-impregnated blocks on each blade and thermo/abrasion resistant PDC cutters in the bit center. Extreme drilling conditions presented by the turbine application and formation led to an optimized impregnated segment block geometry to maximize bit durability without impacting efficiency, and a change in hydraulics to maximize cooling and cleaning of the cutting faces.
This paper is the first published examination of the diamond impregnated bit design process and resulting field experience in the Oman application. The study discusses the basis of the bit design and considerations in achieving operator objectives, including drilling as much footage as possible from 4190 m (13,743 ft) measured depth, while maintaining an average ROP of 2 to 2.5 m/hr (6.5 to 8.2 ft/hr). The authors examine the role of modeling and design software in optimizing durability and penetration rate in the hard formation, and they review enabling manufacturing and material advances.
Protecting Motor-Pipeline-Compressor from Liquid Contamination
Authors: Saez Faisa 
Published: November 2015

Abstract
The reliable operation of rotating machinery relies on a holistic system designs approach. Beside the intrinsic reliability of the rotating machinery, designers have to look into suction scrubber sizing and operation, piping arrangement and auxiliary systems like filtration units to assure a problem free operation. In this paper the author will discuss and present the experiences improving reliability of a Motor-Pipeline-Compressor, specifically how to prevent failures due to liquid ingress.
A field experience at a gas processing plant has forced recognition of some of the external factors affecting the reliability of centrifugal compressors with magnetic bearings. Motor-Pipeline-Compressors are widely used in the gas distribution business and has advantages over conventional compressors that the foot print is smaller, no need for mechanical seals, wide operating range and higher efficiency. However the oil & gas application has different challenges and requires a detail understanding of the dominant failure mode for a trouble free operation. In our novel application we found system defects that led to ingress ofMono Ethylene Glycol (MEG) into the compressor electric motor and magnetic bearing housing resulting in failures. These defects are:Cooling gas filtration unit without draining on secondary chamber.Suction scrubber down-comer without liquid seal.Dead leg on the suction header.Suction scrubber undersized.
This paper will present valuable information on key design features and operating practices to achieve a high reliability.
Significance of Fines and their Correlation to Reported Oil Recovery
Authors: Chakravarty Krishna Hara , Fosbøl Philip Loldrup , Thomsen Kaj 
Published: November 2015

Abstract
Condensation, vaporization and volumetric changes are well-studied phenomena that create differences between the properties of oil at reservoir and surface condition. But similar changes in effluent brine properties have not received the same attention. This study attempts to analyze variations in properties of the effluent brine at reservoir and surface conditions.
Various research groups have conducted water flooding experiments. Concentrations of the effluent brines have been reported. In this study speciation properties of these brines have been reanalyzed. The Extended UNIQUAC Model was used to precisely compute the brine speciation. Calculations was conducted both at surface and reservoir (pressure, temperature) conditions. And possible release of fines that remained unaccounted in previous studies was explored.
The calculation at high temperature and pressure showed that during water flooding, significant amounts of fines were released from the core plug. But with a decrease in temperature and pressure (i.e. at surface condition) these produced fines got dissolved in the effluent water. Thus the produced fines were no longer observable at room temperature. A significant increase in the solubility of anhydrite with decrease in temperature is found to be the principal reason for the dissolution of produced fines. The previously unaccounted fines were observed for the following types of experiments: Rock Type: Chalk, Limestone and DolostoneCoreplug Type: Outcrop and Reservoir CoreplugFlooding Type: Spontaneous imbibition and water flooding experimentEOR Strategy: Low salinity, Smart waterfloods and Advanced Ion ManagementRock Origin: Middle East, North Sea and United States
Furthermore a good correlation was observed between the amount of produced fines and the reported amount of oil recovery. Herein it was observed that production of fines increased significantly when the composition of injected brine was significantly altered. The interaction between the injected brines and the existing brine could have led to formation of mobile fines. This trend was found congruent with incrementing oil recovery.
The calculations show that brine speciation at reservoir condition is significantly different from that at surface conditions. During EOR waterfloods significant amounts of fines are produced which are closely correlated with the increments in oil recovery. These produced fines have previously been unaccounted for. The Extended UNIQUAC model can be used to accurately calculate the amounts of these fines.