bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using CFD to Model the Performance of Retrofit Production Separators in Abu Dhabi
Authors: Kharoua Nabil , Khezzar Lyes , Saadawi Hisham 
Published: November 2012

Abstract
An earlier SPE paper described a Computational Fluid Dynamics (CFD) study to model the performance of the three-phase separators in an onshore oil field in Abu Dhabi The aim of the study was to develop better understanding of the multiphase flow in the separators and to compare its performance before and after upgrading of the internals. A combination of the Eulerian-Eulerian multiphase and k-ε turbulence models was used to simulate the complex internal flow behavior.
This paper is a continuation of the previous work. It describes the internal flow behavior and analyses the impact of the various internal components on the flow pattern.
Rock Mechanical Facies; Classification and Use in Carbonate Reservoirs, Offshore Abu Dhabi
Authors: Williams Math P. , Edwards H. Ewart , Bratli Rolf K. 
Published: November 2012

Abstract
Rock mechanics tests on core from Early Cretaceous carbonate reservoirs from a super-giant field offshore Abu Dhabi has allowed definition of rock mechanical facies (RMF). Each of four RMF are based on stress-strain curves and associated strength and elastic parameters. The lab-based RMF correlate with mechanical stratigraphy classes previously defined from core (and that reflect visible differences in lithology and cementation). The RMF are correlated to reservoir zones and inter-reservoir, impermeable dense intervals, with three facies predominantly correlating with reservoir lithologies and one corresponding with primarily dense intervals. However, some reservoir zones, or sub-zones, can lie in more than one RMF. The RMF are, therefore, partly predictable: for any reservoir zone in the field prediction accuracy is to one or one of two RMF classes. This ambiguity is due to two factors: (i) lateral variation of RMF within some reservoir zones based on lithofacies; and (ii) continuity of mechanical properties between RMF classes. There is a change in RMF from crest to flank of the reservoir, as expected, but there is also local lateral variation within the crest of the field. The two RMF representing most of the reservoirs are expected to respond differently to field operations. Therefore, mapping lateral variation of RMF for some reservoir zones may provide a basis for implementing different reservoir management practices in different areas/zones of the field. The ultimate use of this information will be to enable full-field rock mechanics simulation of the reservoir to help understand the long-term effects of different production strategies.
Completion and Stimulation Methodology for Long Horizontal Wells in Lower Permeability Carbonate Reservoirs
Authors: Jackson Alfred , Al Azizi Badr Musabbeh , Kofoed Curtis , Shuchart Chris , Keller Stu , Sau Rajes , Grubert Marcel , Phi Mike 
Published: November 2012

Abstract
In this paper, a new carbonate stimulation methodology and its impact to the planning of very long, open hole completions will be presented. While the key objective of stimulation is to connect the well to the reservoir, completion equipment design and related well performance have become more important factors. Traditional methods of stimulation modeling and fluid placement are no longer sufficient for these types of wells.
This paper introduces how completion design becomes more complex for more aggressive stimulations. For example, completions with pre-drilled or slotted liners for stimulation with coil tubing acid wash are less sophisticated than ball drop liners for high-volume acidizing or fracturing. In long horizontal completions, computer modeling of stimulation needs to address the flow conditions caused by liners, swell packers and inflow control devices (ICDs). Recent well planning for a long horizontal pilot well (Pilot Well 5) has included the use of new carbonate matrix stimulation software to design a fit-for-purpose completion liner that will accommodate bullhead treatment of a long completion interval. Various completion designs were considered based on objectives from reservoir engineering and geology. Being part of a pilot well program, the strategy is to test fit-for-purpose liners that would balance completion cost with long term productivity and recovery.
The well design required more than 100 runs of the new carbonate matrix acidization software to finalize a liner design that employs over 200 holes distributed along the length of the lateral. The final design was developed to accommodate uncertainties in the reservoir properties and allow for safe and reliable rig operations. The resulting design could serve as a lower-cost alternative to ball drop stimulation liners for long openhole completions.
Drilling Multi-Lateral Infill Wells for Incrementing Oil Production. A Case Study from a Mature Field
Authors: Zuckmeyer E. , Mathadil A. , Gunasan E. 
Published: November 2012

Abstract
The offhsore oil field, situated offshore Abu Dhabi, has been operated by TOTAL for nearly 40 years. At the time of development it was estimated that recovery of the original oil in place would be recovered and that the field would be abandoned shortly. Since the early 1970s, however, many new innovative technical solutions have been employed to improve recovery and maintain economic production; one such technology has been the progressively complex multi-lateral wells that have been successfully used to drain smaller and smaller pockets of residual oil. As a consequence, recovery today is high and with certain reservoir layers reaching a record recovery factors in a carbonate reservoir.
The Upper reservoir, concerned by the advanced drilling technology, is composed of alternate layers of anhydrite and dolomite. The numerous horizontal barriers created by the anhydritic beds have led to the presence of 5 different oil-water contacts and variable, but generally poor, natural aquifer pressure support. In addition, the pressures and oil API were different and caused independent dynamic response to the production. The intermittent tight, intermediate and permeable layers also further complicated the development. Due to all these difficulties, the recovery factor is less compared to other reservoirs in the field.
Initially the production from the reservoir was with vertical wells but then deviated wells began to be drilled from the fixed platforms. The pressure support was provided by peripheral water injectors. The deviated wells were useful in targeting remote areas of the reservoir but, since the layers were thin, the exposure to the reservoir was limited. Also, this resulted in the permeable layers being more developed than the tight layers due to the commingled production.
To improve the oil recovery, an innovative technology was applied for the first time in 1997. TOTAL introduced the drilling of multi-horizontal drains. The completions were innovative allowing for gas lift and selective, independent production of each drain as necessary. Depending on the physical properties of the targeted layer, the proximity of nearby wells and drilling feasibility, the drain lengths ranges from 300m to 1000 m.
Since 1997, over 30 Multi-lateral wells have been drilled with up to 6 branches per well and targeting layers as thin as 1.5m. Many wells have used up "dead" slots, thus adding incremental reserves with limited impact on existing facilities. After 14 years of experience drilling such wells, this paper provides a Case Study highlighting the production benefits as well as a review of some of the technologies that were introduced to achieve them.
Novel Design and Implementation of Kuwait's First Smart Multilateral Well with Inflow Control Device and Inflow Control Valve for Life-cycle Reservoir Management in High Mobility Reservoir, West Kuwait
Authors: Das Om Prakash , Al-Enezi Khalaf , Aslam Muhammad , El-Gezeeri Taher , Ziyab Khalid , Fipke Steven R. , Ewens Steven 
Published: November 2012

Abstract
Increased hydrocarbon recovery and accelerated production from ultra-high water mobility oil-wet reservoir requires the application of advanced well completion technologies to address premature water breakthrough, reservoir management, production management and extended reservoir contact from a single well location. The Burgan Reservoir of Minagish Field, West Kuwait has active aquifer, very high permeability sands associated with active faults and contain highly viscous reservoir fluid with downhole viscosity of 40cp, enhances water mobility and resulted in premature water breakthrough with increasing water cut trend within few months of production as confirmed from well performance of existing horizontal wells. This has resulted in to non-uniform reservoir depletion, by-passed oil regions and low oil recovery.
The Kuwait's first smart level-4 multilateral well was completed in Burgan reservoir by combining the Level-4 junction along with stacked dual lateral completion having customized viscosity independent Inflow Control Device (ICD), customized two Inflow-Control Valves as well as down hole gauges, wide operating range Electrical Submersible Pump (ESP), suitable wellheads, X-MAS tree and Integrated surface panel for real time data monitoring.
The smart multilateral well has assisted in addressing premature water breakthrough, enhanced dry oil production and facilitated uniform depletion, which results in improved hydrocarbon recovery. The paper covers the customized design of smart Level-4 multilateral well by taking in to account the reservoir and its fluid characterization, well architecture, implementation and specially designed invert emulsion drilling fluid for effective wellbore cleanup to achieve formation virginity. The improved reservoir management and production management results are also mentioned in this paper.
From 360 Deg Health Safety Environment Initiatives on the Rig Site to Structured HSE Strategy: A Field Case in Abu Al Bukhoosh Field
Authors: Cuvex-Micholin Marc , Baccino Bernard , Essel Philippe 
Published: November 2012

Abstract
TOTAL Abu Al Bukhoosh (TABK) has irritated a well sequence with the Perro Negro 2 rig (PN2); a Jackup MODU. The rig contract started early January 2010 and may be extended till end of 2015, based on HSE and technical performances.
Since day one, it has been decided to boost the HSE performance with robust Management Leadership, Engineering HSE and ergonomics, and working on the Employees behavior. This well known drilling industry approach has been augmented by TABK decision to surpass general standards. Two additional Safety Officers providing 24 hours HSE coverage were hired by the Rig Contractor. One Rig Site Safety Advisor was mobilized by TABK. Their constant presence provides a close working relationship with the front line workers and Team Leaders. Several audits and ‘’360 Deg’’ HSE initiatives were able to increase the HSE awareness of all.
PN2 has no recordable incident since 900 days. Initially, the HSE initiative and audit plans were based on the experience of the Managers offshore and onshore and not really linked to a formal ranking of the risks.
New sophisticated tools are being developed in the Oil & Gas Industry to rank risks: For example, TABK HSE and Asset Integrity Departments are working on Technological Risk Assessment and Threat Registers. Multi-yearly mitigation measures and action plans are proposed. The well recognized ‘’likelihood-consequences’’ matrix has been adopted also for rig operations. It allows for highlighting the risks per area and the main population involved, ranks the areas per overall risk, and thus develops an audit/frequency plan related to those risks.
With such structured and formalized HSE strategy, risks are well captured, type and frequency of the audits are straight forward, and barriers are implemented for a residual risk ALARP.
This paper will explain in greater detail how this was achieved, the challenges that were encountered during the implementation of the tool, and how the Team intends to continue to add value in such a new HSE culture orientation.
Air Emission Reduction & Zero Flaring & Venting
Authors: Mian Mahboob , Al Qubaisi Nawal 
Published: November 2012

Abstract

Gas Processing Facility (GPF) project achieved Zero flaring
1.7million standard cubic feet per day (41.65 tons) gas recovered thru Vapor Recovery System and protect the environment by reducing;
CO2: 3,924 tons/yr
CO: 123.6 tons/yr
NOx: 21.6 tons/yrs
➢ Total gas recovered: 612 million standard cubic feet per year ➢ Revenue saving: 835,380 US$ /year

Vapor Recovery Unit (VRU):
Under this unit, gases from the Tertiary Ethyl Glycol (TEG)Dehydration package and vents from compressors dry gas seals are recovered/ captured and compressed in the VRU and then sent to the suction for the main gas compressor for reuse instead of going to flare
Gas Processing Project (GPF) at Zakum complex is a new gas treatment platform that will augment the existing gas processing capacity of the Zakum West Super Complex. It will increase the associated gas production from Zakum oilfield. The beauty of this project is that ADMA has employed the Zero flaring policy. There will be no flaring at all at this platform. This is one of the unique project of its nature in the ADNOC group of companies, even in Emirates and could be in the whole middle east where is there would be NO flaring. We have designed flare as well in this project but that would be used only for emergencies.
GPF is a stand alone platform with independent utilities and support facilities. The GPF platform is 67.5 meter in length and 43 meters in width. GPF is located at Zakum oilfield, offshore facility about 65 kilometer Northwest of Abu Dhabi. This platform has three main decks, cellar, mezzanine and main. The flare structure consists of a 120 meter long flare bridge with a 80m above sea level angled boom. The distance from the flare tip to the GPF platform is 150 m. There will not be any flaring during normal operation of the GPF, as Zero flaring technology is installed. Hydrocarbon from the GPF platform will be recovered using a Vapour Recovery Unit (VRU) facility. Flaring will only be undertaken during emergency conditions.
Modeling of a New Single-Well EOR Piloting Technique: Application to CO2 EOR
Authors: Kristensen Morten , Ayan Cosan , Ramamoorthy Raghu 
Published: November 2012

Abstract
Screening and piloting of enhanced oil recovery (EOR) methods is often a lengthy process requiring large financial commitments. The reservoir uncertainty and, for some EOR methods, the lack of fundamental recovery mechanism understanding, call for a careful and staged screening and piloting program before committing to full-field implementation. The MicroPilot* single-well in situ EOR evaluation is a new piloting technique which allows for rapid and cost effective testing of EOR methods under in-situ downhole conditions. It is a log-inject-log technique conducted with a wireline formation tester, where a small quantity of EOR fluid is injected and the resulting change in oil saturation then determined based on a set of openhole logs that are run both before and after the injection.
The MicroPilot is a proven piloting technology for alkaline-surfactant-polymer (ASP) EOR. In this paper, we investigate the feasibility of extending this new technology for testing of CO2 EOR. We demonstrate through detailed analytical and numerical modeling that the changes in oil saturation and composition expected during the CO2 EOR process are measurable by the openhole logs when taking into account logging tool resolution. Based on a test library consisting of 13 different oils, which have been carefully characterized to match experimental PVT data, and all of which are likely candidate oils for miscible CO2 EOR, we investigate the expected pilot response when injecting CO2 both above and below the minimum miscibility pressure. We further study the sensitivity of the pilot response to gravity effects as well as residual oil saturation to the CO2 flood.
Derivation of Immobile and Non-vaporizing Residual Oil Saturation under Miscible Flood from CO2 Coreflood Experiments
Authors: lizuka Ryo , Al-Shehhi Hamad Rashed , Al-Hammadi Hamdan Mohamed 
Published: November 2012

Abstract
It is important to predict the amount of bypassed oil in EOR gasflooding since some portion of the flooded domain may be uncontacted by the injected gas due to reservoir heterogeneities residing in various scales. In this paper, we present a new method of deriving immobile and non-vaporizing residual oil saturation under miscible flood (Sorm, Hiraiwa and Suzuki 2007) from the results of CO2 coreflood experiments. We also demonstrate that Sorm is a sort of upscaled parameters able to absorb complex heterogeneous features in the finer scale.
We history-matched CO2 coreflood experiments using the two different simulation models: one-dimensional (1D) homogeneous model with Sorm and two-dimensional (2D) heterogeneous model without Sorm. Both of these two models replicated secondary- and tertiary-mode CO2 coreflood experiments using core and fluid samples acquired in one of the Abu Dhabi's offshore fields. Hence we successfully obtained the Sorm based on the coreflood experiments for further use in evaluating CO2 injection in a real reservoir. In addition, we effectively modeled the core-scale heterogeneity using the X-ray computerized tomography (CT) data and pore size distribution (PSD) data derived from mercury injection capillary pressure (MICP) tests in the 2D model.
Development of Flank Areas in a Giant Carbonate Field with Optimal Well Placement of Horizontal Wells
Authors: Khan Sameer , Al-Shabeeb Ali , Jani Zankar , Azoug Yousef , Minh Nguyen , Patel Harshad 
Published: November 2012

Abstract
Flank areas pose a particular field development challenge in giant fields with low dip where the transition zone is spread over a large area. Successful development of flank areas depends on accurate reservoir characterization, in particular, water saturation distribution in addition to the optimal placement of wells, both areally and vertically. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact using lower well counts. Proper spacing and vertical placement of horizontal wells are, however, critical. Well spacing is closely linked to oil recovery, pressure support, and sweep efficiency. Similarly, placement of horizontal wells in the right layer is vital for maximum vertical sweep. In order to test initial concept in the field, two existing producers were converted into injectors and pressures were monitored at the offset producers. Surveillance showed that the injectors were able to support producers 1 km away. This paper describes the process of arriving at the optimal well placement for maximizing oil recovery in the flank areas. This study is applicable to giant oil fields with large flank areas which pose significant development challenges.
Multi-Phase, Multi-Component Simulation Framework for Advanced Recovery Mechanisms
Authors: Moncorgé Arthur , Patacchini Leonardo , de Loubens Romain 
Published: November 2012

Abstract
Numerical modeling of advanced recovery mechanisms at the reservoir scale (e.g. miscible or immiscible Gas1 flood, chemical flood, steam injection…), typically implemented in a tertiary phase, is essential to reasonably estimate their potential benefit and to rank the various field development options. In this perspective, using a unique advanced-physics simulator for the entire life of an asset is a desirable objective, because in addition to saving engineering time spent in data conversion, it ensures continuity of the models at all times. In our view such a tool, expected to be flexible and allow reactivity for testing new models, should come as a complement to optimized and robust industrial-grade simulators used for prediction and history matching during primary and secondary recovery.
In this paper we present the prototyping framework implemented in our In-House Research Reservoir Simulator (IHRRS), enabling easy integration of new physics for improved recovery processes with the well-known Black-Oil and K-value or Equation of State compositional models. As a demonstration example, we choose Surfactant-Polymer (SP) flooding, possibly requiring an additional Microemulsion phase. The framework is based on a natural variables formulation, solving a coupled system of conservation equations for the hydrocarbon and aqueous components (and optionally for the energy), simultaneously with a set of local thermodynamic constraints. These constraints enforce the equilibrium of hydrocarbon and aqueous components across the different fluid phases, including the equilibrium of Water and Oil with Microemulsion.
To ensure compatibility between the different recovery mechanisms handled by our system, as well as to facilitate their development and benchmarking, special attention has been paid to developing physical options as plug-in functionalities. For this purpose, instead of relying on complex software engineering tools we prefer the approach of using low-level interfaces to communicate between the core and the modules (such as the fluid, the petrophysical, or the surface facility modules). Most of our modules are entirely independent from each other, and can be compiled as stand-alone programs to be called by MATLAB® or Python scripts for instance; symmetrically, they could be replaced by external software in order to test third party functionalities.
As a first benchmark of our IHRRS, we consider a surfactant-polymer flood scenario in a 2D anisotropic quarter five-spot setting, and compare our solutions against those of a reference academic chemical flooding simulator (UTCHEM). The potentialities of our framework will then be demonstrated on a simplified model of a real Middle-Eastern field.
Increasing the Agility of Process Safety Management Systems
Authors: Rains Brian 
Published: November 2012

Abstract
The oil & gas industry is constantly adapting to change, be it related to price, technology or market demand. High prices of crude oil and advances in technology have allowed producers to access resources previously out of reach, and extract maximum value from these resources. With this, however, operational risk is significantly augmented - both upstream and downstream. In order to cope with this increased risk, it is vital that oil & gas companies have a process safety management (PSM) system that fully integrates management of change methodologies.
DuPont has developed a PSM system that fully integrates change management across multiple facilities, among personnel and in light of technological advancement. While these must be considered singularly, it is also important for companies to build a holistic system that accounts for the interdependent nature of operational systems, and thus address process safety from every possible angle - training and skill development to hazard analysis and maintenance. However, as only a limited number of procedures can be universally applied to cope with changing process conditions, this paper will also detail the means through which companies can develop customized solutions for specific conditions and contexts.
By developing a model that can effectively manage change, it is possible for oil & gas companies to not only avoid catastrophic incidents, but also increase the overall safety of an operation, while concurrently maximizing efficiency, cost-effectiveness and quality.
The extraction and processing of oil and gas is a highly technical mechanical operation that involves volatile and corrosive substances in often extreme conditions. As such, it is vital for companies within the oil & gas sector to develop a holistic PSM system that can successfully manage process safety, while remaining agile enough to respond to specific issues, and any changes thereof.