bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of CO2 and Nitrogen Injection at Low Temperatures in High Temperature Reservoirs for Improving Oil Recovery
Authors: Hamdi Zakaria , Awang Mariyamni , Basyouni Ahmad , Hematpour Hamed , Bataee Mahmood 
Published: November 2016

Abstract
Gas flooding methods have been used as successful tertiary recovery agents for decades. Recent studies suggested the effectiveness of using low temperature CO2 injection in high temperature reservoirs. With respect to current economic limitations, nitrogen and CO2 seems to be one of the most conventional ways to improve the oil recovery. The high temperature reservoirs may not be suitable for isothermal gas injections as they would suffer from gravity override of the gas, while low temperature injection could minimize the effect. The main goal of this study is to compare the low temperature injection of these two fluids in high temperature reservoirs aiming to improve the oil recovery.
To obtain a proper comparison between CO2 and nitrogen, several simulations have been constructed and performed. Thermal compositional runs seem to be the perfect candidate to achieve the goals of this study. The results suggest that with equal injection amount and duration of both fluids, liquid CO2 is a better candidate for improving oil recovery. Ultimate recoveries for CO2 and nitrogen injection at same initial conditions were recorded as 73% and 55%, respectively. The effectiveness of liquid CO2 for oil recovery was recorded as 1.52 barrels of oil for each barrel of injection, whereas a barrel of nitrogen recovered only an average of 0.65 barrel of oil. The viscosity reduction was more severe in liquid CO2, which suggests better mobility for the oil than in nitrogen injection. The CO2 breakthrough happened at an earlier time than nitrogen but due to much higher ultimate recovery, it can be overlooked. The overall conclusion suggests that low temperature CO2 injection can be considered a beneficial and promising method for enhancing oil recovery in high temperature reservoirs.
A Multiple Contaminant Tolerant and Eco-Friendly Water-Based Mud System for Superior Down Hole Performance
Authors: Amanullah Amanullah 
Published: November 2016

Abstract
Millions of barrels of water-based muds are used each year to explore and exploit oil and gas resources both in the onshore and offshore drilling environments. Conventional water-based muds usually have poor contaminant tolerance and hence trigger different borehole problems in down hole conditions. Some of the contaminant induced borehole problems such as induced loss of circulation, poor hole cleaning, stuck pipe, etc may cost thousands of dollars for a single well and thus may increase overall drilling cost dramatically. This highlights the technical and economic significances of a high contaminant tolerant water-based mud for current and future drilling operation.
Dedicated research conducted by Saudi Aramco lead to the development of a high contaminant tolerant water-based drilling mud system that is immune to mono and divalent salts, drill solids and cement that are usually encountered in any drilling operation. Experimental results at room and elevated temperature indicate excellent contaminant tolerance capacity of the newly developed mud system. The mud is environment friendly, virtually non-toxic, OHS friendly and thus expected to eliminate the scope of any short and long term occupational health and environmental hazards.
Due to high contaminant tolerant and no/negligible environmental impact, the newly developed water-based mud is expected to be an excellent drilling fluid system to be in the forefront of best drilling practices in sensitive environments.
Basin Scale Geomechanical Modeling of Tight Carbonate Reservoir in Abu Dhabi: Implications on Pore Pressure Development
Authors: Fadipe O.A. , Bouhlel A. , Noufal A. 
Published: November 2016

Abstract
The in-situ stress state in a rock mass is widely recognized as being of major importance in unconventional field. The inherent variation of stress distribution associated with geological environments is widely recognized as being a key factor in an unconventional field; hence, the need to understand from the basin-scale phase is critical. The three main ingredients needed to formulate a model for the mechanics of the porous sediments, are the concepts of bulk stress, pore pressure and compaction. Most available rock-stress-based numerical engines uses default laboratory properties for the set of lithology's in their library. However, understanding the mechanical properties of the lithologies and applying such to the model makes the result more representative of the local geology.
This paper is an update on the previously published model (Mohamed et al., 2015), exploring the impact of rock stress and external geomechanical boundary (otherwise known as tectonic stress) on pore pressure development and rock failure. Middle Cretaceous formation (layer of interest ~ 150 m) was sub-divided into seven layers based on mechanical log signatures. Athy's law, formulated with effective stress combined with 3-D rock stress based on poro-elasticity, was used in the forward modeling simulator to improve the pore pressure prediction. Depositional events such as erosion and hiatus periods were also taken into account during simulation. The development of porosity, pore pressure, temperature, stress and related rock failure through time were simulated and calibrated to measured data. The main geomechanical properties, such as Young's Modulus, Poisson ratio, cohesion and friction angle depend on lithology and porosity. Appropriate relationship were established and ultimately used to calibrate the first–pass rock properties prediction from the numerical engine. Model porosity is dependent on burial depth, weight of the overburden sediment columns, and lithology properties. The mean stress was ultimately considered in deriving pore pressure results.
Results reveal a dynamic representation of the three principal effective and total stresses within the studied formations. The maximum stress shows a NE-SW trend in the synclinal area and N-S trend on the anticlinal structures, the medium stress shows N-S trend on the synclinal structure with an E-W and NW-SE trend on Well A and Pseudo-well A wells respectively. The minimum stress reveals a NW-SE direction on the synclinal area and N-S trend on both flanks. The model also shows an improved pore pressure result ranging from 26.97 – 42.50 MPa (with 28.46 MPa average values within layers of interest) revealing ~ 1450 psi (10 MPa) difference when compared to the previous model where rock stress modeling was not performed.
Consequence Assessment for Weapons Impact of Process Plant
Authors: Vickers Matthew , Rettie Colin , McKechnie Douglas 
Published: November 2016

Abstract
Historically, deliberate attack on Oil and Gas process facilities has been excluded from process safety assessments and the consequences of weapons impact are not frequently studied. It is noted however that consequence modelling techniques for weapons attack have been developed independently for buildings and structures protecting personnel. In the modern geopolitical and international security climate, facilities may be subject to attack with little warning. Additionally, larger munitions, previously only associated with national forces, are more commonly held and used by insurgents. Plant operators and designers need to understand the hazards posed by such weapons when deciding on the mitigation required. Responses range from complete shutdown of a threatened facility to continued operation with risk reduction measures including plant and personnel protection, reduced manning, reduced inventory and operational restrictions. Abbott Risk Consulting (ARC) Ltd. has experience of applying munitions assessment to process plant situations and this paper presents the lessons learned in combining the, generally separate, disciplines of process plant hazard analysis and munitions effect analysis.
Munitions cause damage to structures and equipment by a number of mechanisms including: overpressure, fragmentation and kinetic penetration, with or without subsequent explosion. The paper discusses the general characteristics and hazards from commonly-available munition types, from small arms and hand held missiles to artillery shells and larger vehicle-mounted rocket systems.
Case studies are presented for the impact of munitions on a conceptual Liquefied Natural Gas (LNG) facility including process plant, full containment LNG tanks and manned buildings. The importance of assumptions regarding the damage mechanism, particularly between fragmentation and kinetic penetration, is demonstrated. Methodologies for combining such munitions studies with process safety techniques, including event tree analysis of the hazard frequency, are discussed such that a scenario-based risk assessment can be produced. "Conditional Risk", the risk of undesired consequences given that an attack takes place, is proposed as the most appropriate risk measure for such studies since the greatest unknown is usually the probability of an attack.
Factor Affecting Sustainable Design and Materials Selection for Offshore Topside Facilities Projects
Authors: Alyafei Ezeldine , Ogunlana Stephen 
Published: November 2016

Abstract
Offshore oil and gas operation is growing rapidly with the high demand for energy as oil is still the most important source of energy. Many studies indicate that the discovery of future oil will be more in the offshore area than onshore. However, the huge offshore facilities and activities create negative environmental and social impact as well as consequences ranging from air and water pollution to health and safety. Therefore, sustainability in offshore operation and design is a major challenge in the offshore industry. This paper explores and identifies the factors affecting sustainable design and materials selection for offshore topside facilities.
A qualitative approach has been adopted in order to develop and identify the factors affecting sustainable design and materials selection for topside offshore fixed platforms. The methodology has been conducted in two parts comprising: 1) an exhaustive literature review to determine the criteria considering the sustainability dimensions (environmental, social, economics) as well as the technical and engineering aspects. 2) A semi-structured face-to-face interview, which included both an open-ended and closed-ended questions component. In order to take into account both the views of oil operators and of the consultancy offices, forty experts and practitioners across the engineering disciplines in oil and gas industries were interviewed. Twenty-four experts from an international oil operator company and sixteen experts from an international consultancy office took part in the study. Seventy-seven criteria were identified via the exhaustive literature review and were distributed into seven subgroups. Relative importance index (RII) was utilized to rank the factors and the groups of factors based on the responses from the experts. Moreover, the internal consistency was calculated in order to check data quality and reliability of the scale.
The findings revealed that all 77 factors are highly important with minimum RII value being 0.640. The criterion offshore evacuation plan and clear escape route was considered the most important criterion among the 77 factors, whereas, the group of offshore health and safety was considered the top among the groups.
Since a limited amount of researches have focused on the sustainability for topside facilities of the offshore platforms, this research fills the gap in the existing knowledge of the offshore industry by contributing the following areas: exploring and identifying the factors affecting sustainable design and materials selection for topside facilities of offshore platform. In addition, the future research may take into consideration the determinant factors from this research in developing a decision framework for topside projects in terms of materials selection and sustainable design.
Real Time Dynamic Simulator for a Multi-Phase Pipeline System to Increase Production and Reduce Operational Costs
Authors: Pagliuca G. , Riviere R. la , Clercq M. Le , Lisdonk S. van , Macnair C. 
Published: November 2016

Abstract
Liquids handling is often a challenge for the production of gas-condensate brown fields. The gas flowrate declines for ageing fields while the water-gas ratio increases. To be able to sustain a stable production in which the amounts of liquid arriving at the downstream facilities can be handled, it is of importance to be able to accurately predict the pipeline liquid inventory in the pipeline.
An offshore Shell operated asset in the North Sea was regularly struggling with flooding of the slug catcher, onshore and offshore facilities trips, too high salt concentration in the production water, etc. The limited prediction capabilities of the offshore production network was identified as one of the root causes of these operational issues. As result of this a real time online simulator was built to better predict the liquids arriving at various operation scenarios.
The simulator consists of a UniSim Design® model with Compas (Shell proprietary multiphase transient pipeline simulator) for the pipelines that has been connected to the production database with the help of a dedicated UniSim Design scripting interface. This real time online simulator can follow the production history of the field and it can predict the future production features. Such a model can help with optimising the production by providing a better prediction of the pipeline liquid holdup and of the downstream liquid arrival rates at various operating scenarios. This can also decrease costs by optimising chemical injection rates for e.g. hydrate inhibition. At any moment in time a copy of the simulator can be made available and "what if" scenarios can be simulated to estimate the impact of a specific operation.
The deployment of this technology helps the asset to reduce the field OPEX and to increase the system uptime with a consequent reduction in production deferment.
An Effective Reservoir Pressure Measurement and Fluid Sampling Methodology in Tight Formations
Authors: Sultan Mir Asif , Ali Muhammad , Hegazy Gehad Mahmoud 
Published: November 2016

Abstract
One of the main challenges in exploration / appraisal phase is to measure the reservoir pressures and sample down-hole single phase fluids to identify the fluid types in tight layers (permeability &lt;1md). This challenge escalates when multiple reservoirs are exposed in same open-hole with varying differential pressures across them. A novel wireline formation tester (WFT) technique was applied in an open-hole condition to collect in-situ representative fluid samples faster and cost effectively. It also significantly reduces the risks associated while sampling across multiple reservoirs in comparison to the conventional techniques.
Conventional approach of using dual packer module requires longer set-unset time as well as pumping out the trapped volume between the packers before receiving fluid from the formation. On the other hand, the probe module is more effective for sampling in high permeability layers. In tight reservoirs, the fluid sampling is very challenging due to low formation withdrawal rates, high drawdown and elongated station times. These challenges were overcome with a radically designed WFT that utilizes a 3D elliptical probe module with an optimum reservoir contact area. These probes enable circumferential flow from the formation with a faster cleanup process and hydrocarbon breakthrough.
The new sampling technique showed an improvement, over the conventional methods in several aspects: (1) Tight zone pressures are obtained faster with lower supercharging effects. (2) In-Situ representative fluid samples are acquired in tight reservoirs above saturation pressure enabling proper fluid characterization PVT studies. (3) Stationary times during sampling are reduced due to negligible trapped volume. (4) Set and retract timing is shorter so that a new sampling method of retract-move-reset is developed to minimize the mud invasion between multiple settings. (5) Reduces the differential sticking risk in longer operations with multiple reservoirs exposed in the same open-hole. (6) Minimizes the sampling runs resulting in significant cost saving. Logging operation proved to be successful with the new sampling method by acquiring representative fluid samples in tight formations, which was not possible earlier.
This paper describes a case history and recent achievements made in acquiring representative single phase fluid samples in tight reservoirs, overcoming the challenges and risks associated with conventional sampling techniques.
A Novel Approach to Maximize Hydrocarbon Liquids Recovery in Gas Compression Systems
Authors: Al-Zahrani Talal , Soliman Mohamed , Salu Samusideen , Ansari Nisar 
Published: November 2016

ABSTRACT
This paper evaluates a technical new approach to establish the optimum operating conditions of associated gas multistage compression systems. The target is to maximize the total steady-state hydrocarbon (HC) liquids recovery of the surface producing facilities utilizing available resources and without any the need for plant modification. Maximizing liquids removal from associated gas has several benefits to gas-oil separation plants (GOSPs) such as increasing crude oil throughput, exporting leaner gas through pipelines in addition to other advantages that will be highlighted through two implemented case studies:
Abu Ali Plant (Arab Extra Light crude oil producing facility). Manifa Central Processing facility (Arab Heavy crude oil producing facility).
The concept is basically to raise the after-cooler's operating temperature (minimize cooling) of the lower pressure compression stages, to enable shifting rich/heavier gas to the optimum side where it is more favorable for the HC heavy ends to coalesce and condense. At that point, the after-cooling is maximized to collect the liquids from the discharge knockout (KO) drum of the highest pressure compression stage. This setup, when compared to conventional setup, which is maximizing the cooling across all stages, yields higher overall HC liquid recovery from the associated gas.
In case study #1, where condensate removed from the gas compression plant is normally spiked in the crude production, this approach was evaluated and field tested, resulting in gain of 2,000 barrels per day in export crude for the same GOSP feed rate. In addition, 50% drop in export gas water load and 25% drop in the HC's dew point was achieved, which helps mitigating pipeline corrosion and slugging issues in export gas transport, given the unavailability of a gas conditioning system in the facility.
In case study #2, where condensate removed from the gas compression plant is segregated and shipped to downstream facilities, this approach was evaluated, field tested and resulted in a gain of approximately 5,000 barrels per day in export condensates for the same GOSP feed rate. This gain resolved a chronic low velocity issue in the export condensate pipeline and helped mitigate water, solids settling and associated corrosion problems in the pipeline as well as downstream facilities upsets.
Application of Nitrate Based Fluid as a Completion Fluid
Authors: Sangka Nataniel B. , Budiman Hendra 
Published: November 2016

Abstract

Objectives/Scope
This paper is expected to be a lesson Learns of using nitrate-based fluid as an alternative solution to improve drilling performance and production optimization old wells.

Methods, Procedures, Process
This Lesson Learns begins from literature studied, laboratory test, field trials and continuous improvements.

Results, Observations, Conclusions
Nitrate Completion Fluids have good solubility for wide range of contaminants. Furthermore, it may have some well stimulation effects. Return permeability testing of sandstone coring samples after immersion fluid completion Nitrate, in some conditions, showed some increase in the value of return oil permeability (Ko) from 25.55 to 36.25 mD.
In the field of applications, it has been tested as an additive and drilling mud on one of the deepest wells in Indonesia (5850 m) in Seram. As the additive, used in NaCl polymer mud system in order to reduce levels of solids and chloride, without changing the other mud properties significantly. With decreased levels of chloride, the corrosion rates of drilling and production equipments are also decreased. As a completion fluid, Nitrate CF have been used in the workover wells in South Sumatra and Riau. As a washer on perforation wash job, it is capable of delivering up to 20x increase in oil production and gas production compared to the previous 3x. Operationally, it has not been recorded for any Non Productive Time related this fluid.

Novel/Additive Information
Nitrate based fluid is an alternative completion fluid products that have been developed as an additive, mud drilling and stimulation fluids. Nitrate based fluid is sold in powder or liquid forms. Nitrates are also the basic ingredient of fertilizer. Nitrate Completion fluids have a density specification up to 1.75, the corrosion rate is lower than 10 MPY @350 deg F with standard carbon steel corrosion coupon, 5 NTU turbidity and pH 6-9, with pH buffering capacity, so it has a resistance to contamination of sour gas, having properties endotermic and environmentally friendly reaction.
Multiple Water Zones Isolation Techniques in Horizontal Open Hole Case Study
Authors: Arif Naveed , Mahmoud Gehad , Buzdar Mudasar , Ali Andaleed , Ali M. , Sanchez Isidro 
Published: November 2016

Abstract
Designing and drilling of an optimized horizontal well has always been challenging due to limited subsurface data available to the petroleum geoscientists. The situation becomes more complex where water bearing zone is encountered at both heel and toe of the horizontal section facing abrupt structural changes primarily due to faults. In order to avoid excessive water production and in some cases even abandoning the well, an innovative technique was proposed and implemented to isolate the undesired water bearing zones.
This paper describes the procedures followed when selective zonal isolation was applied successfully in an onshore well. The well was planned to be drilled horizontally in a thin layer reservoir with limited structural control. While Geo-steering, LWD data revealed the abrupt change in structure along with faults; deeper than prognosis. Consequently the first ~500 ft of horizontal section had to be drilled in water zone. Decision was made to continue drilling up-dip into an oil bearing zone. A major vertical fault was encountered in later part of horizontal hole also. Further investigation in subsurface data revealed that this fault is crossing multiple formations and have high chances of connecting the current horizontal hole to the bottom water bearing zones.
In order to resolve these problems, a forward-looking approach was adapted to isolate the water bearing zones at both the heel (near 7" liner shoe) and the toe. Two different isolation assemblies were run and set in horizontal open hole one by one, instead of using conventional cement plugs before running the completion.
The isolations of these sections were done before running the final 3-1/2" single oil completion which secured the well from abandoning, early water breakthrough and excessive water production.