bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Investigation of Non-Darcy Flow Regime Transitions in Shale Gas Production
Authors: Berawala Dhruvit Satishchandra , Østebø Andersen Pål 
Published: November 2019

Abstract
Shale gas reservoirs are organic rich formations with often ultra-low permeability. Gas is stored in free and adsorbed form. Conventional Darcy flow cannot fully describe the gas transport in such porous media. It is thus crucial to study the shale gas production considering different flow regimes and time dependent permeability, which can improve well-induced fracture design and ultimate gas recovery. In particular, this paper will focus on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable.
The model describes a representative well-induced high permeability fracture surrounded by shale matrix. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Pressure diffusion is the main driving force for single phase gas flow from the matrix to the fracture and from the fracture to the well. Pressure dependent gas desorption is defined by Langmuir's isotherm and is a key production mechanism. The composition and flow properties of free and desorbed gas are the same. This model is implemented in Matlab using Marcellus shale field data.
Scaling the model shows that recovery of gas depends on two dimensionless numbers that incorporate geometry relations, time scales of flow, intrinsic variables of the porous media, non-Darcy constants, adsorption and boundary conditions. The model is initialized using laboratory and field scale measurements and investigated by sensitivity analyses. The dimensionless numbers define if the fracture or matrix control the gas production rate. When one of the media limit production, the non-Darcy flow mechanisms in the other medium have reduced importance due to lower rate in that medium. In such cases, it is less important to include non-Darcy mechanisms. It is also concluded that slippage effects impacts gas production but can be accounted for in a simpler manner in the model. By checking the magnitude of selected dimensionless numbers, the modelling approach can be determined in advance and huge computational time can be saved.
The proposed model provides a tool for interpretation of complex shale gas production systems. It can be used for screening of flow regimes at different operational configurations and hence appropriate modelling approaches. The model can be used to optimise fracture network design and potentially in identifying stimulation operations that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.
Successful Float Over Installation by Portable DP Vessel
Authors: Abu Bakar Azlan 
Published: November 2019

ABSTRACT
Float over topside installation has become a cost effective alternative for offshore construction over the past 25-30 years, as ever-increasing integrated topside weight constantly exceeds the lifting capacity of installation vessel cranes.
The basic concept of float over installation is to transport the topside on a vessel in one piece, position the vessel over the substructure, and lower the topside onto the substructure while maintaining the position of the vessel.
While this basic principle of loadout and transportation remains the same, methods and systems used to execute the concept vary significantly, and pose numerous technical and operational challenges.
PETRONAS Carigali Sdn. Bhd. (PCSB) undertook the development of BARDEGG-2 and Baronia EOR project located offshore Sarawak, Malaysia within South China Sea. Baronia B Central Processing Platform (BNCPP-B) was installed in May 2017 and was the first PCSB's float over installation by a portable Dynamic Positioning 2 (DP2) vessel.
A Deck Transportation Vessel (DTV) was upgraded with DP2 capability by adding two portable azimuth thrusters to allow safe and efficient installation of the topside. Sea trials and annual DP trials were conducted in ensuring DP functionality and performance in compliance to Class requirement. Float over engineering was performed including float over design criteria, hydrodynamic analysis and mating analysis. All outfitting, secondary steel works and grillage structures were installed on the vessel before mobilization for transportation and installation of BNCPP-B Topside.
The operation required high precision engineering and execution considering the close proximity between BNCPP-B Topside and existing BNQ-B platform during the vessel approach towards BNCPP-B Jacket. Additional control measures were taken for safe execution. DP checks were conducted at certain intervals while approaching the jacket. BNCPP-B Topside installation commenced at first daylight on 22 May 2017 and successfully completed by noon.
It has again proven that float over installation by portable DP2 vessel was technically feasible and would be an example for future projects undertaking the same approach. Having a vessel with portable DP2 system will help to optimize the vessel utilization and improve overall project cost.
This paper aims to highlight the float over methodology for BNCPP-B topside using portable DP2 vessel and the technical challenges for offshore execution. The activities during the float over operation, analysis and simulation methods are also presented in this document.
This paper should be an interest to those who will perform the offshore installation via float over method utilizing Portable DP Vessel.
Sequential Failures in Incident Investigation Process Hindering Prevention of Incidents
Authors: Tayab Muhammad , Valappil Suhail , Shah Vishal , Azhibekov Takhir , Zeinati Michel , Al Ameri Mohammed , Al-Hameli Fatima 
Published: November 2019

Abstract
Over the last 10 years, Oil & Gas operations have come under tremendous pressures due to increasing production demands and economic conditions, demanding higher performance and venturing into technically challenging operating conditions. Operating with aging facilities in harsh environmental conditions and higher crew turnaround, have resulted in higher number of serious incidents. Prevention of incidents remains high on the agenda of oil & gas companies and focus is placed on incident investigations to identify root causes of incidents and development of corrective actions. However, repetition of incidents with similar findings and causes have been observed, raising concerns if right root causes were identified and focused corrective actions were identified and/or implemented.
An extended analysis of over one thousand (1000) incidents was conducted to assess degree of repetition of causes and regrouping of causes to assess linkage of human factors with organizational behaviours. It was found that 31% of incidents were triggered by human errors & mistakes whilst 27% were attributed to violations. All violations were deemed as intentional & routine and further investigation was not undertaken. Management Supervion & Employees Leadership was identified a leading root cause category of incidents and this category contributed 20% of incidents followed by Work Planning (18%) and behaviour (12%). 55 % of incidents were caused by human factors and hauman factors were triggered by errors and mistakes rather than violations.
Often efforts are exerted to to influence individual's behaviour however human attitude (cognitive, emotional and commitment) is overlooked as linkage between attitude change leading to behavior change, not fully explored. However, linkage from behavior change to attitude change is much stronger. If worker consciously change their behavior, it requires re adjustment of associated attitudes to align with the new behavior. Positive reinforcement is an effective tool to influence individual's behaviour. If discipline and punishment are used to discourage unsafe behavior, the intended results are not achieved (e.g., incident or near miss are not reported for fear of sanctions).
Assessment of non-compliant behaviors (Violations, mistakes and errors) & conditions and factors influencing such behaviors are often not evaluated and focused action plans to address abilities and motivations with due consideration to isolated or systemic conditions are instrumental in preventing incicidents.
Multi-Scale Compaction Well Operability Limits
Authors: Garzon Jorge , Hsu Sheng-Yuan , Shenoy Karthik , Tenny Matthew J. , Meier Holger A. 
Published: November 2019

Abstract
Wells that are used to recover hydrocarbons from reservoirs are subjected to large amounts of complex geomechanical loads that may compromise the well's integrity over its operating lifetime. While the reservoir depletes, the pore pressure in the rock reduces and the effective stress in the rock formation increases. As a result, the rock deforms and the reservoir experiences an overall volume reduction (compaction). Under such compaction, any well casing experiences a substantial amount of compressive and shear stress/strain in all directions. In order to ensure safe operation of a well, it is necessary to impose operational limits (drawdown and depletion) so that stresses imparted on the casing do not exceed the casing strength. This problem has been studied in the past [1,2,4,6,8,10] and due to computational complexity and cost, past methodologies have used simplified analytical solutions or decoupled modeling by separating the large scale deformation of the rock (3D model) from the casing behavior (2D model). These simplified methodologies rely on choosing an a priori failure mechanism and also make assumptions on how the load transfer happens between the rock and the well hardware. Based on our experience, this approach is conservative and leads to poor approximations. In this study, a fully detailed two-scale 3D Finite Element (FE) model is used to simulate various drawdown and depletion combinations derived from a reservoir model simulation. The large-scale model captures the far-field effects of drawdown and depletion as well as the effects of neighboring producer wells. The small-scale model includes details such as casing, cement, perforations, and surrounding rock. This approach is not constrained to a specific failure mechanism (axial compaction, pipe collapse, bending or shear), but rather includes all possible deformations based on rock mechanical behavior, stress, pressure change, and geometry. Thus, complex casing deformations with different failure locations can be observed.
This technology has been applied to a number of business units within ExxonMobil, allowing us to establish practical drawdown/depletion limits. In this paper, we discuss a field example of this approach.
Evaluation About Adsorption Gas and Free Gas Content Inside Shale Matrix under a Wide Range of Atmosphere Conditions
Authors: Sun Zheng , Shi Juntai , Yang Zhaopeng , Wang Cai , Gou Tuobin , He Minxia , Zhao Wen , Yao Tianfu , Wu Jiayi , Li Xiangfang 
Published: November 2019

Abstract
Much attention has been attracted by the successful development of shale gas reservoir in recent decades. Correspondingly, research aspects of shale gas reservoirs become more and more heat among the academic community, especially in the fields of nanoscale gas transport mechanisms as well as the storage modes. Fascinated by the craft interactions exerted by organic or inorganic shale surface, drastic discrepancy takes place in terms of the gas behavior inside the nanoscale dimension and that in conventional dimension. It is crucial to figure out the exact influence on shale gas recovery and overall production efficiency due to the above large difference. Notably, this paper is designed to comprehensively explore the methane storage behavior in shale nanopores, expecting to provide the direct relationship between adsorption gas and free gas content under various environmental conditions. Also, a novel and simple prediction method with regard to ultimate gas recovery is proposed, which is connected to the pore size distribution and formation pressure. First of all, the gas storage modes in a single nanopore with defined pore size are analyzed seriously. As a result, the evaluation model is constructed for adsorption gas and free gas content in a single nanopore. After that, an upscaling method is applied to extend the adaptiability of the model from single nanopore to nanoporous modia. Finally, sensitivity factor analysis work is performed and a recovery prediction methodology is developed. Results suggest that the adsorption gas content will be a larger contribution to total gas content when it comes to small pore radius and low formation pressure. In contrast, free gas content will increase with the increasing pressure and pore size. More importantly, pore size distribution characteristic has a key impact on gas storage modes and ultimate gas recovery. The high proportion of small nanopores plays a detrimental role on gas recovery, resulting in large content of adsorption gas at low pressure, which will not be produced and remain in shale gas reservoirs.
Direct Thickening of Supercritical Carbon Dioxide Using CO2-Soluble Polymer
Authors: AlYousef Zuhair , Swaie Othman , Alabdulwahab Amin , Kokal Sunil 
Published: November 2019

Abstract
Two major applications of injecting dense carbon dioxide (CO2) into the petroleum reservoirs are enhanced oil recovery and sequester CO2 underground. For enhanced oil recovery applications, CO2 has low miscibility pressure causing the swelling of crude oil and reducing its viscosity therefore improving the macroscopic sweep process. However, the low viscosity of injected CO2 compared with the reservoir fluids causes the fingering of CO2, which may lead to bypassing huge amount of oil, early breakthrough of CO2, and increasing the gas to oil ratio (GOR). The use of direct thickeners, such as polymers, is one of the techniques used to increase the CO2 viscosity. Nevertheless, the solubility of polymers in CO2 and the high cost of soluble polymers are the main challenges facing this technique. In this study, a novel, soluble, and cost-effective thickener is proposed to directly increase the CO2 viscosity.
In this study, a PVT high pressure and high temperature (HPHT) apparatus was used to evaluate the compatibility and the solubility of the thickener in dense CO2. Also, a custom designed apparatus was used to measure the viscosity of dense CO2 in the presence of the thickener at different conditions. The assessment was conducted at different experimental pressures, temperatures, and thickener concentrations. The effect of pressure on the solubility of the thickener in CO2 and on the measured viscosity of CO2 was evaluated at 1500, 2000, 2500, and 3000 psi. Also, the influence of temperature was evaluated at 25 and 50°C. Moreover, the concentrations used to study the effect of thickener concentration on the measured viscosity of CO2 ranged between 0.10-2 %.
The results from laboratory experiments clearly demonstrated that the addition of the thickener at certain conditions can significantly impact the dense CO2 viscosity. The results revealed that there must be a minimum pressure at which the thickener dissolves in the dense CO2. The solubility of the thickener can occur when the CO2 is either in the liquid or supercritical phase. The results also pointed out that the CO2 viscosity increased as the pressure increased. The increase of CO2 pressure can significantly impact the solubility of the thickener in the dense CO2 and consequently the CO2 viscosity. The increase of the thickener concentration also had a significant impact on the measured CO2 viscosity. The results showed that the CO2 viscosity increased with the thickener concentration. The CO2 viscosity increased 100 to 1200 -fold as a result of adding the thickener depending on the experimental conditions
Optimization of Corrosion Inhibitor for a Gas and Condensate Field
Authors: Hirano Susumu , Sunaba Toshiyuki , Sasaya Kazuyo , Kobayashi Atsushi , Yorozu Hirokazu , Iijima Hironari 
Published: November 2019

Abstract
Qualification of a new corrosion inhibitor was carried out for both tubing and flowline services in a gas and condensate field because the production condition changed. The methodology and result of the inhibitor evaluation under a sweet condition was summarized. The depth of production well is 4,500 m and the bottom hole temperature and pressure are 180 °C and 50 MPa respectively. Two brands of corrosion inhibitors had been used for production tubing and flowline respectively in the field. A new inhibitor was investigated for the both applications. The performance of corrosion inhibitor efficiency was evaluated with a rotating cage autoclave. In order to evaluate the tendency of emulsion forming, Oil, brine and an inhibitor were poured into a centrifuge tube and it was shaken intensely. Gas chromatograph - mass spectrometer (GC-MS) and Fourier transform infrared spectroscopy (FT-IR) were studied to measure the residual amount of inhibitor. Finally the field trial was carried out with the new inhibitor. The new inhibitor was adopted successfully for the both services. The GC-MS analysis showed the flow back lasted more than two hours. The risk of emulsion forming became lower because the mixing of two brands of inhibitors was avoided. Reducing the number of the chemicals contributed to reduction of the operation cost too.
Field Application and Performance Evaluation of Polymer Microsphere Profile Control in Low Permeability Oil Reservoir
Authors: Jia Yuqin , Yang Haien , Cheng Chen , Li Zhiping , Hou Ganggang , Yuan Xinyu , Zhao Wenyue , Zhang Zhen , Liu Tongjing 
Published: November 2019

Abstract
During the development of low permeability oil reservoirs in Changqing oilfield, the nonuniformity of injection profile is a commonly seen problem. Conventional profile control methods face the difficulty caused by hard injection and poor reservoir adaptability. Polymer microspheres (PMs) are considered to have good profile control capabilities due to their properties such as hydration swelling and plugging. Therefore, it is proposed to use PMs profile control method to improve the oil recovery in low permeability reservoirs. There are two key factors for the success of PMs profile control, which are matching relationship and plugging properties. In this paper, the average pore throat diameter of the pilot test area was calculated, and the hydration swelling properties were studied by measuring the diameter of PMs. The plugging properties of PMs were studied by displacement experiment. Based on the experimental research, in 2016, 4 well groups in Changqing oilfield were selected for PMs profile control. Calculation results showed that average pore throat diameter of the study area was 2.28μm. The diameter of 800 nm named PCE been selected for PMs profile control. The hydration swelling experiment results showed that PCE initial average diameter was 784nm. After 13 days of hydration swelling, PCE average diameter was 2798 nm and increased by 2.57 times. The results of PCE displacement experiment showed that resistance factor, blocking rate and retention rate was 3.5, 71.42% and 96.22%, respectively. The performance of the PCE application in oilfield showed that 11 production wells were effective after PCE injection, and the success rate of profile control was 47.8%. The average validity period was 150 days. And a total of 1365.5t of oil had been increased during the validity period. For the injection wells, the average injection pressure and the thickness of water absorbing layers increased by 1.415MPa and 3.28m respectively.
Correlation of Wellbore Geometry with Geo-Mechanics and Drilling Practices in a Giant Offshore Field in Abu Dhabi
Authors: Iftikhar Choudhry Bilal , A. Shaver Michael , Abdulrahman Alzaabi Mohamed , Toki Takahiro , Al - Ali Salim , Khaled AbdelKarim Islam , R. Oviedo Vargas Mario , Torres Javier , Ahmed Osman Mohamed , Alfonso Mendez Freddy , Vican Kresimir , Yee Lee Chung 
Published: November 2019

Abstract
Over the course of drilling wells in one of ADNOC Offshore fields, there have been numerous endeavors in the Crestal region of the field with each well presenting its unique array of issues and challenges related to well construction, stability and delivery. Even while drilling two identical wells with extremely similar well designs and architecture, the wells encountered different and at times opposite responses from the formations being drilled. This resulted in the well construction becoming more problematic than expected in some cases while in others the situation was completely opposite, thus drilling and well construction went extremely smooth delivering the well ahead of time as opposed to the nearby sister well.
While the denominators may be segregated based on commonality and differences, there is one particular aspect of the drilling process and planning that has been significantly overlooked, the Azimuth of the well particularly in the crestal region of the field. Over the years, investigation into the well trajectory, the well fluids and intrinsic properties have been dissected to arrive at a result but has not produced the expected success. The Azimuthal impact on the resultant seems to have been ignored to the extent of not understanding the Azimuth impact on a well trajectory. It is of paramount importance to investigate and identify the imp act since the related stresses and their directions directly define and drive the stability and the optimal mud weight needed to drill successful wells.