bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of a New Environmentally Friendly Flowback Surfactant and Its Application to Enhance Oil and Gas Productivity
Authors: Rabie Ahmed , Zhou Jian , Qu Qi 
Published: March 2019

Abstract
Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity.
In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated.
The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.
The First Middle East Unconventional Well Stimulation Treatment by Applying WASP® Technology: Field Cases
Authors: Al Harthy Arafa , Al Habsi Khalid , Al Hinai Khalid , Walley Stuart 
Published: March 2019

Abstract
The conventional well stimulation treatments have been used in the oil and gas wells for long time to remove formation damage or skin in order to enhance the well production and be able to achieve economic rates.
Wireline Applied Stimulation Pulsing (WASP®) is a prominent new technology that is gaining more grounds in the well stimulation for oil producer and water injector wells. WASP® is an electro-hydraulic technology that generates repeatable, high power hydraulic pressure pulses downhole over the entire desired interval. The repeated pulsing stimulates the near wellbore area, breaks up scale and causing tensile failures in formation rock, thus creating mini fractures/fissures for new flow paths and removing formation damage or skin caused by scale, fines etc. that were blocking perforations, slotted liners, sand screens or gravel packs, resulting in improved inflow.
Petrogas Exploration and Development recently conducted a WASP® campaign trial that is the first application in the middle east in four vertical wells in the south of Oman oil fields. The wells were Well-A, Well-B, Well-C and Well-D. The vertical wells were completed on the Gharif and Al Khlata sandstone oil reservoirs, which contain relatively medium oil with a viscosity range of 44-239 cP. All the pay zones were perforated, except for Well-B which was completed with gravel pack. The wells were completed with artificial lift including PCP pumps and beam pumps with polish rod strings. It was understood that the poor/low production performance of the candidate wells was due to the high skin, caused by the damaged gravel pack and plugged perforations. The WASP® tool specifications that was run for the treatments of the wells were 2.750" in diameter, and the length was approximately 11.6 m. The conveyance was on electrical wireline cable by using a standard logging truck.
The results of the WASP® treatments jobs have shown mixed results but generally Well-A/B, Well-C and Well-D showed improvement in well performance and consequently in the oil gains. In fact, in Well-C in Aseel field had the highest production rate increased by more than threefold - a remarkable improvement. The other wells are still in the monitoring stage. The operation performance of WASP® treatments went smoothly without any operational issues or lost time in all the jobs. WASP® technology demonstrated that it is an attractive alternative method to the conventional well stimulation methods that involve the use of hydraulic fracturing and injection of acid, solvents and deimulsifiers. These conventional well stimulation methods have limitations in the treatment of the pay zone and operationally intensive. WASP® technology is proven to be more effective, safe (HSE compliant), less time consuming and thus cost effective. Petrogas is now considering applying the WASP® technology to the water injectors.
A Robust Correlation Improves Well Drilling Performance
Authors: Al Rubaii Mohammed Murif , Al Yami Abdullah , Omini Eno 
Published: March 2019

Abstract
Utilization of drilled wells operations’ records is required to perform improvement of performance to minimize drilling cost of planned drilling of new and re-entry wells (workover – wells). Many operators are always interested in finding optimum ways to save on drilling cost. Optimization of Rate of Penetration (ROP) has direct effects on cost reduction. Different Techniques were used to optimize ROP such as regression technique, multiple linear regression technique, neural network, artificial neural network methods, and basic reference of Bayesian networks. There are several factors that will limit application of ROP optimization models in different hole sections with high degree of accuracy. It is the authors’ opinion that modeling on smaller selected section with controlled parameters will give better optimization and validation. In this paper an empirical correlation of rate of penetration (ROP) is presented for a particular hole section. The data selected are from same hole size, formation type and mud type. It is based on monitoring and controlling simultaneously the applied weight on bit (WOB), drill-string's rotation (RPM), Torque (TRQ) and rig pump's flow rate (GPM). During this study will demonstrate the use of this empirical correlation to improve drilling in a hole section by more than 50%. The developed model also has high potential to be automated in real time operating environment to improve drilling performance.
Understanding Reservoir Fluid Behavior to Mitigate Risk Associated to Asphaltene Deposition in the Reservoir Rock Near to Asphaltene Onset Pressure AOP in the Magwa Marrat Depleted Reservoir
Authors: Al-Obaidli Asmaa , Al-Nasheet Anwar , Snasiri Fatemah , Al-Shammari Obaid , Al-Shammari Asrar , Sinha Satyendra , Amjad Yaser Muhammad , Gonzalez Doris , Gonzalez Fabio 
Published: March 2019

Abstract
The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirty-six (36) producer wells have been drilled until now. By 1999, when the field had accumulated ~92 MMSTB of produced oil and the reservoir pressure had declined to ~8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential
Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core- flooding study and 1 permeability/wettability study.
Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 ±500 psia and the saturation pressure is 3,200 ±200 psia.
Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates. Additional field testing and lab research have been proposed to 1) establish an adequate operating envelop for each well to optimize production and mitigate asphaltene deposition in the tubing to decrease downtime due to coiled tubing cleanouts which will reduce OPEX, 2) Support determination of a suitable reservoir pressure depletion to minimize CAPEX by implementing a pressure support project at an optimum reservoir pressure, and 3) Establish an appropriate field development strategy to produce the field at its maximum potential without jeopardizing the health of the reservoir while optimizing ultimate recovery
Barrier and Thermal Performance of Graphene-HDPE Nanocomposites for Pipeline Liner Application
Authors: Samsudin Mohd Shamsul , Ahmad Mahtar Murniyati , Leong Kok Hoong 
Published: March 2019

Abstract
The water barrier performance of high density polyethyelene (HDPE) nanocomposites with different graphene thicknesses and aspect ratios was investigated. Three graphenes with differing thicknesses and aspect ratios were considered for this work. The graphene was blended into the polymer HDPE matrix using a heated internal mixer. The best performing graphene in terms of improved barrier performance was determined to be the one that is thinnest and with the highest aspect ratio. This graphene was further studied for the effects of loading, whereby samples with 0.005, 0.01 and 0.10 wt% graphene, revealed no significant difference between them for enhanced barrier performance. In addition, the degree of crystallinity was also measured and compared between the unmodified and the three graphene modified HDPE. Between the three graphene-HDPE variants, there was no discernible difference in the level of crystallisation of the HDPE. However, it was shown that crystallinity improves by some 15%, corresponding to a measured degree of crystallinity of 65% for the graphene-HDPE, versus 56% for the unmodified HDPE. Thermal stability, on the other hand, did not improve with addition of the three graphenes used in this work. It is believed that the graphene loading used in this work was is low to produce any observable enhancement in thermal stability.
Development of the Arctic and its Impact on International Energy Market
Authors: Akimova Irina 
Published: March 2019

Abstract
Arctic is widely considering as the last world biggest storehouse of natural resources. But its unique nature should always remain the main concern for all the energy projects development in this area. To achieve this development of the Arctic should go along with innovative technologies development. The ambition of this paper is to provide assessment of main Arctic projects on international energy markets development.
Use of Numerical Modeling to Optimize Completion Design of Horizontal Multistage Fractured Well in Unconventional Source Rock under Uncertainty Parameters
Authors: Rabah Mesdour , Mustafa Basri , Ali Habbtar , Aramco Saudi 
Published: March 2019

Abstract
The development of unconventional resources is capital intensive and challenging where operators spend a large amount of resources to maximize value. This is a direct result of completing thousands of wells with multistage fracturing. The optimization of well completion to enhance hydrocarbon recovery will help to reduce development costs and enhance project economics under the uncertainty parameters: geological, engineering, and economic.
The paper demonstrates a novel workflow as an effective way to optimize completion design by integrating advanced multi-stage fracture modeling with reservoir simulation in an unconventional resource play. This work shows an integrated workflow using a compositional dynamic simulation study for gas condensate well. The complexity of gas flow physics in both nano-darcy reservoir as well as hydraulically fractured Stimulated Rock Volume (SRV) are considered. The physics include gas desorption, pressure dependent permeability, non-Darcy flow and gas condensate fluid behavior.
The workflow includes QA/QC of the geologic model with a fine model resolution to map the hydraulic fractures. Long-term flow back data is used to calibrate the simulation model using history matching regions following the analytical trilinear model. After achieving a reasonable history matching, a detailed uncertainty assessment was performed to estimate P10, P50 and P90 of the well's EUR (Estimated Ultimate Recovery) using Proxy modeling workflow. Uncertainty parameters include hydraulic fracture half-length, SRV permeability, dew point pressure, under-saturated desorption pressure, rock compaction trend, etc.
Finally, what-if scenarios were performed to assess the impact of cluster spacing, fracture height, horizontal well length and minimum well head pressure (WHP) on the well's EUR.
The results of this work illustrates the workflow used to optimize well completion design including the number of stages along the lateral, length of the lateral, treatment sizes and how it impacts well performance as well to support management decision making.
Unleash Unconventional Resources with the Power of Light-Laser Technology
Authors: Batarseh Sameeh , Al Harith Abdullah , Othman Haitham , Al Badairy Hameed 
Published: March 2019

Abstract
The objective of this work is to establish a communication between the tight hydrocarbon-bearing formation and the wellbore by using high power laser technology. This paper presents different methods of utilizing the energy of the laser to enhance and improve the flow in unconventional reservoirs including tight formation, the successful results are used for field deployment strategy.
High power laser is an innovative alternative to several currently used downhole stimulation methods and technologies. The system consists of the laser source which is mounted on the surface on a coiled tubing unit, fiber optics cable to transmit the energy and the downhole tool. The advantages of utilizing high power laser technology for downhole applications are the ability to control and orient the laser energy precisely. Laser energy generates heat when in contact with the rock samples, the heat impacts the rock samples by dehydrating, collapsing and dissociating some minerals near the wellbore, as well as creating micro- and macro fractures in the formation. In addition, heat removes the blockage around the wellbore and the effect extends deeper into the tight formation for production.
Continues efforts over the past two decades have been proven that high power lasers provide controllable heat source while penetrating the formation, this mechanism enhances flow properties especially in tight formation. Low permeability in these formations restricts the flow and reduces production. Shale, Sandstones (including tight sandstones) and carbonate rocks have been treated with high power laser. Pre and post-treatment measurements are conducted for comparisons; the results from all rock types show improvement in permeability and flow. The results of advanced core characterizations, imaging and visualization are presented. The success of the lab experiments leads to the development of field deployment strategy to use high power laser for in-situ treatment in unconventional wells.
Utilizing state-of-the-art high power lasers technology in downhole provides innovative and safe stimulation methods. Reliability, accuracy, and precision in controlling the power, orientation and the shape of the beam are some of the properties of the technology that made it attractive for downhole applications. Different tools have been developed for different applications that can fit any slim holes.
The Transport Behavior of Liquid Hydrocarbon in Shale Nanopores
Authors: Zhang Tao , Li Xiangfang , Cheng Zhilin , He Minxia , Yin Ying , Liu Qing 
Published: March 2019

Abstract
Shale, as the "tight" rock with abundant nanopores, exhibits extremely low permeability on the order of micro-nanodarcy. The classic Darcy law, being widely and successfully used in developing the oil in conventional deposits, becomes insufficient for that in deposits of the shale. In this work, on the basis of molecular dynamic simulation data available in the literature, a model for oil transport through a single nanopore is established considering the boundary slip and the varying viscosity of the confined oil. The results show that, to accurately predict the oil transport properties in inorganic and organic nanopores, the viscosity correction for the confined oil transport in the nanopores is necessary. The oil transport capability in organic nanopores is greatly enhanced compared with that predicted by the no-slip Poiseuille equation, significantly enhancing the flow capability in the scale of nanoporous media, while the small slip length in the inorganic matter (IOM) has neglected effect. This implies that the greater concentration of drilling activity needs to be implemented in the region with higher TOC, where there is the "sweets spots" from the point of oil transport.
Innovative Green Solution for Gas Condensate Blockage Removal
Authors: Al Hamad Mohammed , Ibrahim Ezdeen , Abdallah Wael 
Published: March 2019

Abstract
Condensate blockage presents a serious production problem due to loss of gas productivity. Several methods have been proposed to resolve condensate blockage to restore the well productivity, most commonly used technique is hydraulic fracturing. Although, it is most commonly used, it is not always feasible and favorable due to its inclusion of costly chemicals such as surfactants, which could also be as hazardous material. Our objective in the current study, is replacing such surfactants with natural green surfactants which are more economical and environmentally friendly.
Interfacial tension and contact angle experiments were carried out to examine the efficiency of two different natural green surfactants in comparison to two commonly used chemical surfactants in fracturing fluids. The results revealed that natural green surfactant is efficient in reducing the interfacial tension by 74.1% compared to 94.8% when using alcohol-based surfactants. Moreover, the natural green surfactant showed stronger effect in altering the surface wettability in sandstone formations towards strongly water-wet with a contact angle reduction of 61% compared to 32% in the case of alcohol-based surfactants.
Based on the concentration used here, the natural green surfactants are more cost-effective, a product cost reduction of more than 50% can be obtained. Being efficient in reducing the interfacial tension, altering the surface wettability towards stronger water-wet, abundant in nature, environmentally friendly, and, cheaper cost, this new proposed natural surfactant can replace the currently used chemical surfactants for condensate bloackage.
OGIP Estimation from Boundary Dominated Data Using Normalized Variables: A Field Case Application in a Tight Gas HP/HT Field
Authors: D'Windt Adolfo , Al-Saffar Ali 
Published: March 2019

Abstract
Accurate estimation of the Original Gas in Place (OGIP) early in the reservoir life is fundamental as field development plans and ultimate recovery strongly depend on it. This is particularly relevant when the conventional material balance is not suitable due to the lack of pertinent shut-in pressure measurements. This paper presents a case history of a tight gas field in which we use flowing material balance technique and type curves for decline curve analysis to calculate OGIP by using only flowing pressure and rate data.
The method uses fundamental pseudo-steady state theory, which determines that a plot of the rate-normalized pressure drop vs the pseudo-time produces a straight line with the slope of such line yielding the OGIP. The use of the pseudo time concept calls for the estimate of gas properties at the prevailing reservoir pressure which in turn is a function of the OGIP and the cumulative production. We propose an iterative scheme based on the Newton-Raphson method to compute the OGIP using the flowing material balance technique coupled with the conventional P/Z material balance.
We illustrate the application of the method with the aid of synthetic examples as well as field cases obtained from low permeability gas reservoirs where no shut-in pressures are available. Results from the technique adequately compare with type-curve matching analysis. Furthermore, we demonstrate the problem can be transformed into an equivalent-liquid system and being analyzed with standard PTA techniques using the constant rate liquid solution.
In absence of shut-in pressure information, the PSS analysis offers an attractive alternative to the conventional material balance method. Besides, the method only requires minimal phase behavior data in the case of gases rendering its application practical and convenient. Also, we describe how to transform the constant pressure problem into a constant rate one in order to apply standard PTA techniques. Additionally, this work demonstrates the importance of having automated wells with permanent gauges by enhancing the value of the information provided by them in the framework of an adequate and judicious reservoir management.
Smart DAS Uphole Acquisition System for Near-Surface Model Building: Results from the First Successful Field Tests
Authors: Smith Robert , Bakulin Andrey , Silvestrov Ilya 
Published: March 2019

Abstract
Accurate near-surface velocity models are required to correct for shallow velocity heterogeneities that can otherwise lead to the misinterpretation of seismic data, particularly in the case of low-relief structures. Here we show how a novel uphole acquisition system utilizing distributed acoustic sensing (DAS) technology can be used in a number of different ways to generate near-surface models.
The novel smart DAS uphole system connects multiple shallow wells with one continuous optical fiber. The horizontal and vertical segments of the fiber allow several techniques for near-surface model building to be tested using the same system. Uphole surveys use the vertical fiber segments to make accurate, localized velocity measurements, while the directivity of the DAS fiber enables horizontal sections to be used for refraction tomography and surface-wave inversion.
The smart DAS uphole acquisition system, which enables the collection of data for deep reflection imaging and near-surface characterization simultaneously, has been successfully tested for the first time. Data acquired from ten smart DAS upholes produced excellent early arrival waveform quality for picking and subsequent velocity model building. This direct velocity measurement of the near-surface can reduce uncertainty in the seismic interpretation. In addition, replacing the shallow part of the depth velocity model with the DAS uphole model resulted in significant improvements in the final depth image from topography.
The directivity of DAS enables the recording of refracted events on horizontal fiber sections which have been picked as input to refraction tomography. This produces an alternative near-surface model that captures a larger volume of the subsurface. Ultimately, while the uphole velocity model is only suitable for removing long-wavelength components of near-surface variation, the refraction velocity model may allow for the correction of small-to-medium wavelength statics.