bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Batch Processing of Heavy Oil Sludge at Oman (2011 to 2014)
Authors: Nahmad D. G. , Al Ghafri F. , Rasheed R. , Sajid S. 
Published: December 2014

Abstract
Sludge is an intrinsic by-product of the Oil & Gas Industry, it is considered a hazardous waste and there are few technologies within the industry to process it under an environmentally sound protocol.
Sludge to Oil Technology (STO) is a proprietary process utilized to break emulsions of hydrocarbons/water/solids. The process is based on a series of chemical reactions involving surfactants that interact with other reagents in releasing heat and neutralize the non-covalent forces that form the bonds between the substrate and the wetting agent. Final separation is achieved by using specific gravity differential between the different components of the de-emulsified mixture. The byproducts of the reactions are inorganic salts, water and carbon dioxide.
Two different centrifuges are used to achieve a fast and accurate separation. The byproducts of the reactions are inorganic salts, water and carbon dioxide.
This technology has been successfully implemented at the operator site by the contractor under a pilot project. Over the term of the contract, more than 100,000 bbl of raw sludge had been treated meeting the following KPI's: Oil &lt; 1.0% BS&W, Water &lt; 20 ppm OIW and Solids &lt; 1.0% TPH.
The process has been applied in-situ where the emulsions are stored and has recovered more than 50,000 barrels of saleable crude oil. The recovered water has been sent for re-injection and the solids meet all the requirements of the Ministry of Environment and Climate Affairs (MECA) - Oman as a treated waste under international standards. At a time when crude oil prices have reached over $100.00 USD/bbl this technique can prove to be not only environmentally sound but also an addition value to the operator's production bottom line.
The STO process was applied directly in the field where the emulsions are stored and can bring great technical and economical advantages to the user.
At a time when crude oil prices have hiked this technique can prove to be very economical not only for oil recovery, but for also as preventative maintenance and to mitigate from potential environmental liabilities.
Advanced Technique In Designing An Inflow Control Device Completion for The Development Of A Giant Offshore Oilfield In The UAE
Authors: Bachar S. , Khedr O. , Jackson A. , Qotb M. , Alhajeri A. 
Published: December 2014

Abstract
An integrated completion design modeling approach has been implemented for development wells in a giant offshore field to maximize asset value and recovery. The modeling approach enables the selection of lower completion inflow control devices and well path compartmentalization strategy for every well based on predefined criteria.
The development of the field under consideration is progressing with a water flood recovery scheme that requires the use of new technologies to achieve higher oil recovery and controlled water production. Since the only contact with reservoir is the wellbore, efficient reservoir sweep and recovery can only be achieved by putting the right well equipment in the right location.
In this paper, the design process which has been adopted for well completion design using Inflow Control Devices (ICDs) will be shared and explained. An interactive loop is used to optimize the number of ICDs and nozzle sizes using reservoir simulation coupled with specialized well and completion modeling software.
A number of ICD well completion design examples are presented. From these examples, predefined design criteria are applied in an iterative manner targeting optimal sweep and maximum recovery as an objective function. The key criteria elements are:
Predicted water flow mechanism from nearby injectors into the well. Reservoir pressure contrast along the well path and variation over time to account for additional pressure drop imposed by ICDs. Permeability contrast along the well path. Effect of nearby producers, if within the same drainage area.
When concluding the detailed completion design, the outcome is shared with the Drilling operation team for fine-tuning, materials selection, materials procurement, and implementation. Further modeling work will be discussed covering the impact of the stimulation design resultant skin on predicted recoveries.
Innovative Approach to Increase Name Plate Capacity of Oil and Gas Gathering Centre: A Case Study of North Kuwait Facility of Kuwait Oil Company
Authors: Parikh Chirag , Al-Saeed Abdulaziz , Mahmoud Bader A. , Kukreja Rajiv 
Published: December 2014

Abstract
The Oil and Gas gathering and processing facility of Kuwait Oil Company was built with a nameplate capacity of X MBOPD with 50% water cut. However, the facility was operating with a water cut of 35% since its commissioning in year 2011. This comprehensive technical study was conducted to evaluate possibility of increasing oil processing capacity of this facility in line with current lower water cut and other operational flexibilities available in the facility without utilizing its design margin.
This paper shares an innovative approach to increase name plate capacity of oil and gas processing facility utilizing available operational flexibility and operational margins with minor modification. It shares a case study where facility capacity is increased by around 19% without utilizing design margins of equipment or pipeline. Such approach can easily be applied to all similar facilities across oil & gas industry.
The study confirmed that facility name plate capacity can be revised from X MBOPD (with 50% w.c) to X+32 MBOPD (with 45% w.c). It is observed that minor modification in control loop of separator to utilize three phase separator as two phase separator, lower water cut of the feed stream and margin available in feed specification of Desalter trains are major contributors to get leverage in increasing name plate capacity of facility.
The paper provides detailed guideline for such out of the box technical evaluation of facility to operate it at higher capacity without any major modifications which will result in significant financial / production gains for any organization.
Challenge of Acidizing Horizontal Wells in Tight Carbonate Reservoirs - Weak Acid and Non-acid Alternates
Authors: Punnapala Sameer , Rahman Maryam Abdul , Misra Sanjay 
Published: December 2014

Abstract
Horizontal wells have become a norm in ADCO for effective and efficient reservoir recovery. At present ADCO is embarking on development of tight carbonate reservoirs where permeability ranges from 0.2 – 10 mD. While carrying out a review of the 214 acidization jobs conducted from 2005 to 2013 in two of ADCO's fields, it was found that conventional acid stimulation with 15% hydrochloric acid in horizontal wells in tighter parts of the reservoirs did not seem to provide expected results. Use of selective stimulation in segmented completion and diversion also did not yield the desired results. The reaction rate of 15% hydrochloric acid is too fast to create effective wormholing when tightness of the reservoir exceeds certain degree. A thorough survey of market and the published literature was carried out to analyze the root cause of the poor performance. Wormholing is the desired mechanism for carbonate stimulation, which is governed by the reaction kinetics and rate of transport. Optimal wormholing is obtained at a right balance between these two mechanisms. Literature is abundant with references on use of weak acids and non-acid stimulation chemicals like acetic acid, chelating agents and nano emulsions for stimulation of carbonate reservoirs. These chemicals have an advantage over 15% hydrochloric acid in terms of wormholing potential owing to slower rate of reaction. The study revealed that in a field, permeability and length of treatment are the main parameters in deciding the optimal stimulation chemical. A correlation was developed based on the kinetic parameters of various chemicals and field experience which can act as a guide in selecting the right acidization formulations. Such correlations will go a long way for ADCO in acid stimulation of horizontal wells in tight carbonate formations.
Modification in Conventional Depressurization Calculation in Quest of More Pragmatic Minimum Design Temperatures in Complex Isolatable Blowdown Zone
Authors: Nandi Bashistha 
Published: December 2014

Abstract
Blow-down system under discussion was complex in nature and Hydrocarbon gas was methane rich. In an isolatable section there were a big inventory of slug catcher, piping, inlet separator and two trains of Glycol contactor getting depressurized by two BDVs simultaneously. For such a big system it would be unrealistic to consider a single bulk vessel (as Aspen HYSYS does) and use the same Minimum Design Metal Temperatures (MDMT) throughout as different section had different Surface area upon volume ratio and varying thickness. While reviewing (By conventional Aspen HYSYS Blow down calculation) Minimum Design Metal Temperature (MDMT) of equipment inside blow down inventory and Flare network, it was found that metallurgy needed to be more exotic than selected during FEED as inner wall temperatures were much lower than selected particularly for Piping as heat transfer co-efficient (HTC proportional to velocity^0.8) in piping is much higher than the vessel. As changes involved a significant cost and a common MDMT throughout such a complex system seemed to be impractical, Aspen HYSYS Blow down utility calculation had been modified by considering credit for actual surface Area, actual metal mass, volume averaged thickness and splitting the system in several hypothetical blow down zones to arrive at much practical MDMT and exotic metallurgy was averted.
The above non-conventional MDMT study can find significant application for appropriate selection of metallurgy in complex blow down inventories in gas processing industry and avoid over conservative exotic metallurgy selection.
Rigorous Blow down calculation and minimum temperature analysis were taken up in-house and most pragmatic MDMTs were predicted at different parts of the complex section and appropriate metallurgy selected with respect to predicted MDMT by the study and significant project cost was averted. The blow down study subsequently was verified by a Third Party Consultant through a Dynamic Study and existence of problem, methodology applied and recommendations were acknowledged and approved by them.
Based on above study, exotic metallurgy hence significant cost to the project was averted in a recently concluded gas processing project in Algeria.
Successful Execution of Offstream Inspection at ADCO NEB Asset
Authors: Al-Marzouqi Abdulla 
Published: December 2014

Abstract
ADCO North East Bab (NEB) field is located at approximately 90 KM from Abu Dhabi town. It comprises of two Central Processing Plants (CPP); one at Al Dabbiya (DY) and the other at Rumaitha (RA). The two plants are located 20 KM away at the west and the east side of Al Sila road respectively.
NEB field consists of around 165 wells (some located in clusters and other are remote wells) along with pressure vessels, connected piping and pipelines. Pressure vessels located in clusters are mainly Closed Drain Vessel or Oil Test Separator. The Central Processing Plant (CPP) at Al Dabbi'ya consists of two trains of oil treatment and stabilization while CPP at Rumaitha consists of one train. In addition to oil treatment, the CPP includes facilities for storage & export, gas compression & gas drying, water injection, water treatment & disposal, and utilities. All vessels/equipment in CPP are in service since 2006.
In October 2013, ADCO-NEB asset successfully carried out off-stream inspection of twelve (12) pressure vessels located in various clusters. Equipment covered were mainly Oil Test Separators and Closed Drain Vessels. Subsequent to off-stream inspection of pressure vessels at clusters, random on-stream inspection of piping in both the CPP was also carried out.
This paper highlights the salient points in successful and safe handling of the off-stream inspection and presents the case study of two major findings. Vessel bulging: Inspection revealed bulging of one of the horizontal closed drain vessel located in one of the on-shore cluster. A closed drain network and a closed drain vessel are installed in clusters to collect drained fluids from Oil producer Wellheads, Piping manifolds, Gathering manifolds, Test separator, Pig traps, PSV discharge and Let down station when installed. The closed drain vessel is open to the atmosphere through the cold vent stack.Flare Header corrosion: CPPs have extensive network of Flare header piping which includes LP, HP, Cold and Tank Flare headers. During on-stream inspection, random ultrasonic thickness survey of piping revealed severe internal corrosion of Low Pressure (LP) flare header. LP flare header combines with HP flare header and Cold flare header and discharges to HP Knock Out drum. Perforations were also noted on the several locations. Consequently, shutdown was taken and LP header was replaced with the new piping.
This paper also describs in brief the root causes analysis of above failures and corrective actions taken. Timely detection of these damages prevented the potentially more severe failure consequences.
Review of BP's Global Gas Injection Projects
Authors: Jhaveri Bharat , Brodie James , Daae Victoria 
Published: December 2014

Abstract
Miscible gas flooding is an established method for enhancing oil recovery that can be successfully deployed in secondary or tertiary mode. BP has developed a range of innovative techniques to maximize economic oil recovery from its miscible gas floods. While some of these gas floods have been applied early in field life, in other cases gas flooding has significantly extended the life of mature, water-flooded fields. The results have been reported in a series of publications over the past three decades. The purpose of this paper is to provide an overview of BP's experience of establishing, managing and optimizing miscible gas floods.
Prudhoe Bay (Alaska) is the world's largest rich hydrocarbon miscible gas project. Conventional and unconventional methods have been applied in a variety of different settings in secondary and tertiary mode. An extensive surveillance program has facilitated a good understanding of the processes operating at field scale and routine surveillance data are used to optimize the flood. In 2002, a large-scale gas cap water injection project was implemented to slow the decline in field pressure. This project has enhanced the efficiency of the various recovery processes operating across the field, resulting in additional recovery. As a result of the success in Prudhoe, miscible gas flooding has been extended to numerous other fields on the North Slope of Alaska.
BP has two active miscible gas projects in the North Sea, Magnus and Ula. In both cases, gas injection began after extensive water flooding. Tertiary miscible water-alternating-gas (WAG) flooding in Magnus field started in 2002 after construction of a gas pipeline from fields located west of the Shetlands and its impact on reservoir performance is significant and well understood. Tertiary miscible WAG injection in Ula field started in 1998 and has played a key role in arresting production decline. In both fields, the miscible gas flood is currently being expanded. In addition to these miscible gas projects, BP jointly operates a CO2 injection project in Algeria and, with its heritage companies, has a long history of operating CO2 floods in the US. BP is actively pursuing new opportunities for gas flooding around the world.
Miscible gas injection has generated considerable benefits for BP over the past three decades and will continue to do so. The potential availability of large sources of CO2 in the future, supplied by carbon capture, could help maintain a leading role for miscible gas injection for years to come.
A Novel Approach for Reservoir Simulation and Fluid Characterization of Unconventional Fields: Phase 1 Molecular Level Considerations
Authors: Diaz-Campos Mery , Hobson Stephen 
Published: December 2014

Abstract
In spite of the Shale Gas revolution, that has changed the dynamics in US supply and while today's combination of hydraulic fracture and horizontal drilling has made certain shales economic. This study presents that the fundamentals for fluid behavior in Unconventional reservoirs remain unknown. As the amount of reserves in the world is massive, today's technologies and workflows need to evolve more and systematically apply the correct science to extract full value of every shale.
Unconventional fields contain hydrocarbon fluids that are under strong influence of their pore-walls. The reason for such behavior is attributed to pore-size distribution being at nanometric level (10-9m), widely demonstrated by scanning electron microscopy (SEM), simulation and adsorption data (Diaz-Campos et al., 2008; Ambrose et al., 2009). At this tiny scale, fluid behaves different to what it is known conventionally.
Current methods for calculating gas reserve in a typical unconventional field attempt to take such complexity into account by modifying methods used in conventional fields without definitive and clear success. The modified method utilized today is known as modified "Langmuir isotherms" (M. Gasparik et al., 2012). Such approaches require detailed isotherm analysis in the laboratory and iterative calculations to estimate its unknown constants Langmuir volume (VL) and Langmuir pressure (PL). It has added variables to the Langmuir's equation, adsorbed methane density, adding complexity to the original equation and making its application difficult if not impossible. Furthermore the constants and added variable are representative to a single well level only, utilizing such values at a reservoir level are prone to compromise the accuracy of the results. Novel approaches to generate datasets for unconventional gas reservoirs are therefore needed.
In this study, it is used a molecular-modelling approach to analyze how hydrocarbon fluids accumulate in such nano-pores and how the pore-size affects its mobility. Molecular modelling is a form of computer simulation (Allen M.P and Tildesley D. J., 2007) that is been used in the biomedical industry, material science, chemistry, chemical engineering and has been evolved to be an essential means with which to explore chemical and physical interactions in unconventional reservoirs.
We characterize methane behavior when confined to a nanoporous medium, by means of Computer Simulation at molecular level. From the results of the fluid characterization at molecular level we observe that methane adsorbed density changes with reservoir pressure. Furthermore we conclude that the methane permeability is reduced with pressure, specifically when the reservoir is above ~5700psia methane shows a liquid-like behavior, such findings generate a fundamental insight about fluid behavior when confined to shale type of reservoirs. The experimental method for validating the MD simulation results is also discussed.
Successful Reservoir Management and Field Development Strategy Through Integration of Field Data Analysis with The Simulation Model - The Case of an Abu Dhabi Offshore Mature Complex Carbonate Reservoir
Authors: Ali Issa Abdelkerim , Uematsu Hiroshi , Bellah Samir , Al Hashemi Mohamed A. 
Published: December 2014

Abstract
A complex heterogeneous carbonate reservoir, located in the offshore of Abu Dhabi, started oil production in 1985. The initial field development plan consisted of drilling crestal deviated producers and peripheral sea water injectors. As the reservoir is highly faulted and fractured with underlying high column of aquifer, water cut rapidly increased by channeling through faults system, reducing oil production. Consequently, the field development team decided to drill horizontal producers, and then later equip them with ESP. In the meantime, water injection rate was significantly curtailed due to uncertainty on injection benefit, which resulted in declining reservoir pressure, limiting production from some wells. In 2012, the team analyzed the historical production data to reassess water injection benefit. The study included areal analysis and correlations of reservoir pressure, voidage replacement ratio, logging data, production decline trends, bubble and saturation maps, and geologic data. The results indicated hydraulic communication between all reservoir areas, increased production decline rate with continuous reservoir pressure depletion due to low VRR and insufficient aquifer support, and poor pressure communication in some peripheral areas due to low reservoir quality resulting in lower transmissibility. Based on the analytical study results, reservoir simulation model was used to optimize water injection scheme, including optimum injector locations and optimum injection volume. Along the process, reservoir uncertainties were assessed through simulation sensitivities. The study results suggested maintaining the current peripheral water injection locations, increasing injection rate to minimize reservoir pressure depletion, working over the existing injectors/drilling new injectors to meet injection volume target, and carrying out further optimization after improved understanding of remaining geologic uncertainties.
This reservoir management approach allows to continuously integrate reservoir geology and field dynamic data to reduce reservoir uncertainties and to optimize field development plan and operations.
Applications of Wintershall's Drilling Complexity Index (DCI) in the Well Delivery Process
Authors: Nzeda Blaise G. , Schamp Juergen H. 
Published: December 2014

Abstract
Wintershall has developed a Drilling Complexity Index (DCI), which is a tool that is used to measure the complexity of a well. It is an early warning indicator and a measurement of how easy or difficult a specific well can be delivered. The DCI can be used at any phase of the well delivery process; from the pre-screening or conceptual phase through the detailed design phase to the execution phase.
Wintershall's HQ based Best Practice unit for Well Engineering (ESW) used well data from existing databases to compare the DCI to other complexity indexes. Furthermore, ESW analyzed the impact of the DCI on key performance indicators (KPI) such as non-productive time (NPT), cost per meter, and meter per day. This paper will present the work performed and the results that show a strong impact of the DCI on all the above cited key performance indicators.
This DCI tool was initially planned to be used by drilling teams to plan wells. Following its successful development and roll out in the drilling groups, Wintershall looked at ways to expand its use and quickly realized that its usefulness extend beyond the drilling groups.
This paper will further describe how the DCI can be used for the following purposes: Predict NPT of drilling projects based on DCIDetermine the time contingency for a wellDetermine the cost contingency of a wellTrigger peer-assists, well examination and staffing of well projectsSupport role in the project approval processPortfolio management
The work which will be presented has accelerated the acceptance and the utilization of the DCI tool within Wintershall, and represents a significant improvement in assessing the inherent risks and hazards and potential consequences for exploration/appraisal/development wells.