bluuebunny/crossref_metadata_2025_split huggingface dataset:
Troubleshooting Glycol Loss in Gas Dehydration Systems Using Data Analysis at Upstream Operation
Authors: Soliman Mohamed , Alwani Mohammed Abdo , Aiderous Abdullah Younis 
Published: November 2019

Abstract
The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques to reduce glycol loss and to meet the product specifications in one of the gas dehydration systems in an upstream gas oil separation plant (GOSP). The gas dehydration system using Triethylene Glycol (TEG) is the most widely used and reliable gas dehydration system in upstream operation. These proven data analysis techniques were used to tackle major and chronic issues associated with gas dehydration system operation that lead to excessive glycol losses, glycol degradation, and off-specification products. Glycol loss is the most important operating problem in the gas dehydration system and it represents a concern to the operation personnel. Most dehydration units are designed for a loss of less than 1 pound of glycol per million standard cubic feet of natural gas treated, depending on the TEG contactor operating temperature.
In this paper, comprehensive data analysis of the potential root causes that aggravate undesired glycol losses degradation and off-specification products will be discussed along with solutions to minimize the expected impact. For example, operating the absorption vessel (contactor) or still column at high temperature will increase the glycol loss by vaporization. Also, the glycol losses occurring in the glycol regenerator section are usually caused by excessive reboiler temperature, which causes vaporization or thermal decomposition of glycol (TEG). In addition, excessive top temperature in the still column allows vaporized glycol to escape from the still column with the water vapor. Excessive contactor operating temperature could be the result of malfunction glycol cooler or high TEG flow rate. This paper will focus on a detailed case study in one of the running TEG systems at a gas-oil separation plant.
New PDC Bit with Hollowed Cutters: with Increased ROP and Longer Service Life
Authors: Zhang Hongying , Chen Huihui , Liu Feng , Wang Na , Huang Yanfu , Fang Zhimeng , Pan Xingming 
Published: November 2019

Abstract
A novel design of PDC bit with hollowed cutters is presented that uses the principle of hydraulic lubricating and water jetting mechanism to improve ROP. Engineering results show its advantage compared to solid fixed cutters which are commonly used in today’s drilling industry.
The structure of the new PDC bit is as follows: each cutter contains a specific fluid channel, which is tailor made; the bit body contains many fluid channels; Compared with the existing conventional PDC bit, the main distinctive features are: the cutters are hollowed, each cutter contains a fluid channel in the centre of itself; and the bit body has fluid passages which are communicating with each hollowed cutter, allowing the drilling fluid flows from the inside of the bit to the outside of each cutter.
The failures of a PDC bit are mostly due to premature wear or cracks of compound cutters; the wear or cracks are due to mechanical and thermal effects. To improve the service life of cutters can effectively increase the life of the drill bit. According to thermal stress analysis, the position where the frictional heat concentrated is in the centre of the cutter, which will result in the generation and expansion of thermal cracks, which in turn leads to failure of the cutter and loss of ROP. Therefore, the cutter with fluid passage will improve the way of thermal concentration and expansion, thereby prolonging the life of the drill bit, reducing the number of trips, improving single run drilling footage, therefore the drilling efficiency is increased. During the drilling operation, the rock cuttings cannot flow out timely, and may accumulate on the drill bit, which is commonly referred to as mud balling. The presence of mud balling will reduce the cutting capability of the drill bit and decrease the ROP. The new PDC bit with hollowed cutters has self-cooling and self-cleaning functions to mitigate the thermal effect, while the pressurized flow from the micro-hole of the cutter has the effect of water jetting, which in turn increases the ROP.
The novelty of the new PDC bit is in the capability to solve the issues of low ROP and short service life of today’s tough drilling conditions, to meet the requirement of a single trip to complete the total depth.
Famous Barriers within the Bowtie Levels Analysis: Creating Middle and Senior Management Understanding about the Relative Importance of Management Activities
Authors: Hudson Timothy , Hudson Peter 
Published: November 2019

Abstract
The paper discusses extending the use of the Frequency Adjusted Measured Effectiveness (FAME) methodology (SPE-190633) to the operational, organisational and cultural levels in bowties. The method enables risk management functions to steer senior management toward effective management actions at the middle management level, allows greater understanding of the cultural and regulatory factors impacting those management activities, and provides a clearer understanding of where the most important impact can be achieved through organisational change.
This paper develops Bowtie concepts by applying FAME (SPE-190633) to the bowtie ‘levels analysis’ (SPE 127180). The ‘levels analysis’ defines the barriers at the levels of a bowtie as the workplace (Level 1, L1), organisational (Level 2, L2), and cultural and regulatory factors (Level 3, L3). FAME quantifies the relative importance of barriers within bowtie systems as a whole. The paper uses these concepts to provide simple ways of providing middle and senior managers with understanding about how well their risks are being managed.
The disconnect between what management does and what actually needs to be done has been shown to contribute strongly to accidents. Without the support of analytical tools to steer decision-making, management activities are generally prioritised on an ad-hoc basis, usually guided by an individual manager's experience as well as senior management pressures. This can lead to important management activities not being conducted as rigorously as they require. The Levels Analysis improves understanding of the middle and senior management roles involved in the management of the risks of the operation, while the FAME methodology supports the understanding of the relative importance of those activities, allowing prioritisation. When applied this allows risk-based decision-making to be applied not only to frontline tasks but also to higher-level management functions. This approach, by looking at all the management functions controlling barriers, allows risk managers to communicate clearly the priority safety critical management functions require to senior managers.
This allows the conversation to change from "why wasn't he wearing his gloves?" to "how did we not have a start-up audit on this contract?" The emphasis is moved from immediate causes that are hard to control to factors that are within the span of control of middle and senior managers. This paper introduces a method for clearly communicating to middle and senior management what their own critical management functions are, which are most important and what they can and should be held accountable for.
Selection of Tubing and Completion for High Sour HPHT Gas Wells – A Success Story
Authors: Pimenta Gervasio , Bux Adeel , Ahmad Mubashir , Baslaib Mohamed , Al Jeelani Omar , Al Rumaithi Fahad , Turniyazov Nurlan 
Published: November 2019

Abstract
Selection of material for downhole completion is a challenging process for appraisal wells, where the uncertainties associated with the reservoir parameters need to be weighted and economically reasoned. This is particularly true for high sour, high temperature, high-pressure (HS-HPHT) gas appraisal wells, where the probability associated with potential release of gases needs to be as low as possible, as the consequences of a release can be very high and potentially fatal.
A corrosivity assessment was carried out for the material selection of tubing and liner of a HS-HTHP gas well with H2S and CO2 in excess of 40% and 10%, respectively. Uncertainties in the simulations were related to the amount of water, and condensate. Previous reservoir data suggested that elemental sulphur would not be present. The well was completed with a 25Cr35Ni alloy for a flow test period of 1 year.
Test separator data revealed a minor amount of water. After the test was completed, the tubing string was pulled out of hole. Visual inspection showed scattered shallow pitting, with some connections revealing crevice corrosion.
This paper describes post-exposure analysis of the completion tubing, relating pitting and crevice corrosion with the fluid and reservoir conditions.
Results of this real-time study allowed setting the requirements and standards for selecting downhole materials, considering the presence of water and elemental Sulphur in the HPHT sour atmosphere downhole.
Furthermore, recommendations were incorporated in the test of FFP materials in such harsh conditions to test against crevice corrosion in challenging reservoir conditions, as a fundamental parameter in the material selection process for FFD. This study represents a valuable document in the current ADNOC strategy of attraction of business partners for development of new concession blocks, especially for HS-HPHT gas and condensate reservoirs.
The New Development of Amphiphilic Polymer Profile Control Agent in High Temperature and High Salinity Reservoirs
Authors: Yang Hongbin , Kang Wanli , Zhang Hongwen , Zhou Bobo , Li Xinxin , Wang Fang 
Published: November 2019

Abstract
Profile control treatment is an effective technology to improve reservoir heterogeneity and decrease the watercut. Polymer gel has become the most widely used profile control agent. The most commonly used polymer in polymer gels is HPAM, which has poor adaptability in high temperature and high salinity reservoirs resulting in poor gel performance. Amphiphilic polymers have good viscosifying action in high temperature and high salinity reservoirs due to the polymer chain entanglement and hydrophobic chain association. In this paper, one amphiphilic polymer (PADC) was developed by introducing a betaine type functional monomer. In order to further improve the anti-temperature performance of PADC, the idea of using inorganic nanoparticles for enhancement was proposed. Based on this, a composite gel with good temperature and salt resistance was developed by adding crosslinking agent. The effects of nanosilica particle concentration, polymer concentration and crosslinking agent concentration on the gel performance of the composite gel were investigated systematically. The results showed that salt viscosifying action ability was related to the ionic strength. The higher the ionic strength, the larger the polymer molecular hydraulics radius. At the same time, the strength of hydrophobic association was improved and formed a denser spatial network structure. The synergistic effects made PADC have the characteristic of salt viscosifying action. It was also found that the viscoelasticity of the polymer solution changed from a viscous system to an elastic system by adding nano-silica, and apparent viscosity increased significantly. We have demonstrated that nano-silica surface will adsorb free polymer moleculesin solution, and form molecular brushes due to charge attraction and hydrogen bonding. The molecular brushes will adsorb and combine with the spatial network structure formed by the amphiphilic polymer. A significant improvement in the gel strength of composite polymer gel compared with organic polymer gel. Our work indicates that the composite gel based on amphiphilic polymer has significantly potential applications in high temperature and high salinity reservoirs, it has certain reference significance for stabilizing oil output and controlling water content for the similar reservoirs.
Rule-Based Systematic EOR Screening Methodology for ADNOC Oil Reservoirs
Authors: Mogensen Kristian , Al-Keebali Aaesha 
Published: November 2019

Abstract
Many of the oil reservoirs in ADNOC’s portfolio have been producing for decades and continue to deliver their target rates, thanks to development schemes centred on pressure support from peripheral water injection and/or crestal gas injection, where applicable, or from line-drive patterns.
As these reservoirs mature, a number of enhanced oil recovery (EOR) techniques are being evaluated to increase the ultimate recovery factor. Choosing one or several appropriate EOR methods starts with a robust screening methodology, which in this case has to apply across an entire reservoir portfolio, rather than just to a single asset.
The key objective of the screening efforts presented in this paper is to estimate the EOR potential from each reservoir in a systematic manner to allocate the right resources, to the right fields, at the right time, with the right technology. Therefore, the screening methodology must take into consideration the following aspects: The focus of the screening is on identifying opportunities, which are or will become technically feasible by the time deployment is requiredThe screening procedure must remain sufficiently high-level to be able to deliver an outcome within a short time-frameA single EOR method is not necessarily applicable across an entire reservoir; hence several EOR methods can potentially be implemented in the same reservoir but in different areasThe thought process (workflow) has to be properly documented so that the screening exercise can be updated whenever new technologies or new relevant field data become available
The new EOR screening tool considers more EOR methods compared to previous screening efforts: It takes a much broader view on potential source gas options for miscible gas injection, namely enrichment of sweet hydrocarbon gas, sour gas streams, CO2 with or without impurities, as well as nitrogen for some high-temperature reservoirs containing volatile oil. This step involved estimating miscibility conditions for hundreds of combinations of injection gas compositions and reservoir fluids using equation-of-state based MMP calculations in addition to common MMP correlations.The reservoirs are all carbonate formations and are characterized by high temperature and high salinity. These conditions have traditionally been a challenge for chemical EOR methods involving polymers and surfactants. However, recent R&D progress has opened up for opportunities not previously considered. Both polymer and foam agents are currently being piloted, which have the potential to change the EOR landscape in Abu Dhabi and perhaps elsewhere as well.As reservoirs mature and breakthrough of injection fluids begin to occur, the need for improved reservoir conformance becomes evident. The success of any EOR technique relies on the right well placement with the right monitoring in place and the right level of injection profile control.
Integrated Approach for Analysis and Forecasting of Chemical EOR Recoveries in Sultanate of Oman
Authors: Al Mahrouqi Dawood , Farajzadeh Rouhi , Alkindi Abdullah , Rifaat Mjeni 
Published: November 2019

Abstract
Polymer injection in the south of Sultanate of Oman has been implemented in Marmul field for the last decade. Recently, alkaline surfactant polymer (ASP) technology has also been piloted in the field, which was technically successful owing to its significant incremental oil production. The current end-game strategy for the field is to follow polymer with ASP flood in order to produce the remaining oil after polymer flood and maximize the ultimate oil recovery factor. This has revealed the need for evaluation of the full-field performance of ASP flood using available tools. Full-field dynamic models are not always best tools for modeling the performance of chemical enhanced oil recovery, primarily due to under-representation of the reservoir heterogeneity, lack of the complementary data, complexity of the process itself, and large computation time. In this paper, we implement a conduit-model approach using field production data from the ASP pilot to assess the ultimate incremental oil recovery. This approach is compared to an analytical model that is based on the modified Koval's method with reservoir heterogeneity as an input parameter. The obtained results are used for preliminary assessment of the difference between polymer and ASP injection in the full field.
Cost Effective Alternate for Inconel on Sour Gas
Authors: Wolters Roy 
Published: November 2019

Abstract
The challenge with HP/HT sour gas fields is compliance with NACE MR0175 / ISO 15156. Moderate partial pressures of H2S already required Nickel based alloys like Inconel. Since these are high pressure fields this means that low concentrations of H2S results directly in materials with high cost and difficulties to supply the proper quality.
Table A.23 of NACE MR0175 / ISO 15156-3 indicates that for Wellhead and Christmas tree Components and valve and choke components an alternate cost effective material can be used.
Table A.23 shows that 13%Cr4%Ni Martensitic Stainless Steel can be used without restrictions to the H2S level for valve bodies in API 6A wellhead equipment. The cast version of this material is widely available at relatively low cost and without quality challenges thus making projects less challenging.
The material has proven itself in use for valves in high concentration H2S fields. In order to prove the material being fit for purpose a test program was conducted, including sour gas testing and FEA work. This work was included in NACE ballot 2013-03 and the proposed change from that ballot was adopted in the current NACE MR0175 / ISO 15156-3 standard.
Effective Production Network Debottlenecking Analysis by Finding Optimum Choke Size
Authors: Almohammad Humoud 
Published: November 2019

Abstract
Oil wells performance can be determined from completed zone productivity, completion type and size, and surface facilities. A significant surface tool, wellhead choke, can profoundly impact on the well performance. Determining the optimum choke size can result in improving the production of the well by altering the wellhead pressure, therefore the pressure drop. Increasing the bean size above optimum might result in decreasing wellhead pressure below flowline pressure and prevent the oil from flowing.
To determine the optimum choke size for oil well; live trial and error could be helpful, though it is not practical and need to be combined with a well simulation analysis and history matching. A multiphase flow simulator is applied on a set of selected wells, having bottlenecks and backpressure issues in Kuwaiti oilfields. The simulation has been developed by choosing a precise flow correlation that presents a reliable flow behavior and pressure drop results. A comparison of different flow correlations was performed against the actual test readings to eliminate a potential error from the simulation against the actual readings.
Changing the choke bean size was a quick, effective, and economical solution to overcome the bottlenecks and backpressure issues in individual candidates. Simulating the formation productivity and assessing the well performance and changing the choke size can increase the successfulness chance of the live trial and error procedure. It can also help in categorizing the wells whether to be a candidate to have choke size change, or another solution is required to flow the well such as a surface pump, artificial lift, or changing the receiving facility pressure, if possible. All the selected eighteen wells are vertical or slightly deviated with an oil API gravity between 32 and 35 degrees, and the flow behavior correlations were between the Beggs and Brill (1973) empirical correlation and the Ansari (1994) mechanistic model. The comparison between multiple sensitivity analyses proved that both models are reliable and can be applied to the selected field. Simulating the wells had increased the choke size debottlenecking approach successfulness rate by 70 percent, and increase the oil production up to 6,000 barrels per day.
A debottlenecking analysis is presented in this project, and supported with data matching and field test results. The procedure to optimize the choke size is explained in details using a multiphase flow simulator and an in-house developed excel sheet. Several additional approaches were analyzed to overcome backpressure issues, like using ESP artificial lift method.
Building More Accurate Models for Different Reservoir Types using Interval and Interference Pressure Transient Testing
Authors: Zeybek Murat 
Published: November 2019

Abstract
Building accurate reservoir models can be quite challenging, especially highly stratified thick intervals in hydraulic communication in reservoir. Presented methodology is based on comprehensive Interval and Interference Pressure Transient Testing (IIPTT) for classified reservoir types with a systematic approach. Classification of reservoir types is based on layering, thickness, and hydraulic communication of layers in the reservoir.
The methodology describes building more accurate anisotropic reservoir models, providing well performance assessment based on integrated comprehensive IIPTT solving with efficient non-linear parameter estimation and modeling with numerical simulation for different reservoir types. The number distributed IIPTTs are optimized to ensure to achieve coverage across total thickness depending on the reservoir type.
It is demonstrated that high resolution accurate reservoir models can be built for relatively thick highly layered reservoirs in a feasible manner.
When Effective Integration Drives the Development: A Successful Case History
Authors: Spelta Elisa , Caronni Valerio , Carrasquero Gabriela , Catanzaro Massimo , Rossi Massimo , Tagliamonte Rita Leda , Valdisturlo Antonio 
Published: November 2019

Abstract
A robust and detailed reservoir model is an essential requirement when a fast track approach drives the development of a green field. Such a tool can only be developed through the orchestration of Geological and Geophysical (G&G) and Reservoir Engineering disciplines. This integration effort is, first of all, aimed at identifying the key characteristics of the reservoir most impacting its dynamic behavior at different scale and, eventually, at capturing them with the proper modelling approach.
This paper decribes such approach to the case of a complex deep-water reservoir belonging to slope-toe of slope environment. A 3D integrated static model was built by incorporating core and log data, their petrophysical interpretation, a description of the depositional and architectural elements, a quantitative seismic reservoir characterization and the few dynamic information available at this early development stage.
The implemented geomodeling workflow focused on heterogenetiy that could affect reservoir performance such as structural-stratigraphic discontinuities that could act as hydraulic barriers. Facies in the interwell space were distributed by applying seismic-derived 3D trends. Facies distribution eventually provided the framework within which petrophysical properties modelling was performed. During the implementation of this integrated G&G and Reservoir workflow, continuous crosschecks of consistency and robustness of the model led to elaborate the final product.
The resulting reservoir model captured critical uncertainties (e.g. degree of reservoir heterogeneity including stratigraphic discontinuities) leading to an optimized development scheme, that allowed to minimize risks, despite the few data available.