bluuebunny/crossref_metadata_2025_split huggingface dataset:
Achieving 50% Plus Oil Production in Asphaltene-Stabilized Emulsion Problematic Field Under Artificial Lift Operation
Authors: Furuichi Naoto , Uetani Takaaki , Yorozu Hirokazu , Sasaya Kazuyo , Shibuya Takehiro , Kiminami Narihito , Yonebayashi Hideharu 
Published: November 2016

Abstract
An oil well in Japan, referred to in this paper as Well B, experienced emulsion problems from the commencement of natural flow production in January 2008. These problems were immediately resolved by the usage of effective demulsifier which was selected through bottle tests. As the well ceased to flow naturally in April 2014, an artificial lifting operation began with a jet pump since July 2014 to maintain the production rate. Shortly after artificial lifting performed, serious emulsion problems recurred even though it was continued to utilize the demulsifier which had worked successfully during natural flow.
This paper presents the details of how we addressed these problems and managed to continue operations. Temperature, retention time and chemical injection were well known as the factors for separating emulsion. First, plant operator planned to raise the processing temperature from the current operating condition of 60°C. However, it was found that temperature higher than 60°C could damage coating inside gun-barrel and tanks which were located downstream of the second separator. Through fine optimization, the processing temperature was set at 65°C not to expose them to higher than 60°C but this was not feasible to separate emulsion. Second, we changed the flow scheme of two production separators from parallel to series connection. This countermeasure didn't resolve these problems essentially but it enabled us to catch almost all emulsions at the first separator. It means that the first separator condition could be reset by draining emulsion periodically from dump valve so that we managed to continue operations with keeping the target water content in sales oil. Finally, a series of bottle tests were conducted to select a better demulsifier to replace the original one, which was no longer effective. Soon after injection of the new demulsifier, the emulsions disappeared and the operator regained the production rate.
This improvement reduced the emulsion disposal cost and man-hour for treating emulsions. Furthermore, oil which had been disposed as emulsions could be sold as product and Net Present Value (NPV) of this asset increased through high production rate operations. The total amount of economic impact reached 2 million dollars.
Control of Contaminates & Degradation Products in Amines During Sour Gas Treatment
Authors: Singh Sanjay Lallan , Veerakumar Ukkirapandian , Abbas Ahmed 
Published: November 2016

Abstract

Objectives and Scope
The objective is to control contaminants in amine systems such as heat stable salt, degradation products, hydrocarbons, particulates and injection chemicals etc. through chemical analysis and process operation. Interpretations of lab results and corrective action in plant to help us to monitor, control and improve the performance by minimizing loss of amine in the system.

Methods, Procedures and Processes
Contaminants are substances which enter the process and "pollute" the amine. Amine contaminants can be grouped into five categories; (1) Heat stable salts, (2) Degradation products, (3) Injection chemicals, (4) Hydrocarbons and (5) Particulates. Degradation Products are contaminants in solution where the molecule is broken down or changes its chemical form. Amines considered for this study are Diethanolamine (DEA) used in LNG plant and Methyl diethanolamine (MDEA) used in OAG and IGD plants. Amines should be color free and devoid of particulate matter. This is achieved through activated carbon and mechanical filters so that amine quality is within established limit.

Results, Observations and Conclusions
Laboratory analyzes amines sample (DEA & MDEA) for various contaminants by simple analytical techniques using titrators, pH meter and Gas chromatograph. The analytical data for amine strength since 2013 i.e. in case of DEA the average is 20.1 % within the range of 18-22 % and for MDEA, the average is 45 % and the range is 40-50 % with marginal exception on some occasions. The foam tendency and foam stability data for last three years are optimum indicating minimum contamination. Chloride and Iron which are precursor to HSS & degradation products are monitored on monthly basis and are well below the maximum control value. HSS in amines were low which indicates the stability of amine. The lean amine after regeneration to strip out H2S and CO2 is passed through mechanical filter to remove fine particles and suspended solids which is further treated through activated carbon filters to remove hydrocarbons, anions, cations, impurities etc. Laboratory analyses are vital links for smooth operation of amine system. Simple chemical analysis helps us to understand and give timely response for process control. Historical data gives the perspective for spotting trend of sampling, analysis and possible errors.
Proper design of mechanical and carbon filters helped us to maintain amine system free of contaminates and healthy minimizing amine loss. The low level of contaminants in amine system ensures integrity of process equipment and associated units.

Novel/Additive Information
This simple analytical techniques and process control helped us to maintain the quality of amine and integrity of plant. The same approach is applicable to any gas treatment plant and can be applied there.
Advances in Pulse Neutron Capture in Evaluating Formation Properties within Low Permeability Carbonates Reservoir Onshore Abu Dhabi: An Integrated Case Study
Authors: Khan Muhammad Faisal , Ashqar Ayham Al , Rawahi Ali Salem , Gashut Mohamed , Hammadi Khaled Eissa 
Published: November 2016

Abstract
Pulse neutron capture (PNC) is an effective technique to monitor lateral and vertical saturation/sweep. Assessing pulsed neutron results in either open-hole (OH) or cased-hole (CH) is key in evaluating formation properties, while with reservoir performance routinely monitored, time lapse logs are compared with the base logs to dynamically assess saturation changes and sweep efficiency.
PNC sensitivity to factors such as invasion, bore-hole and cement; makes its result influenced by rock matrix and fluid properties. LWD logging may minimize the mud filtrate impact; however this is subject to the drilling parameters and exposure.
LWD PNC has been analysed (drill and wipe pass) in both oil and water base muds. Quality assessment is performed on LWD/WL Sigma considering: mud used, invasion, formation water and mud properties. Variable Sigma was used to improve PNC saturation interpretation particularly within the transition zone. The effect of mud was discussed with examples showing its impact on data properties.
WL PNC time lapse logging over five years were analysed, results indicated mud dissipation process masking formation response. Resistivity and pulse neutron saturations are compared. PNC saturation is integrated with resistivity based saturation.
The capability of the pulsed neutron logging to derive meaningful results within the studied fields were examined in both OH, and CH conditions along with the definition of base log and the parameters used to derive saturation. Variable Sigma concept and uncertainty within transition zone is discussed. The used methodology and integration has improved the interpreted saturation, consequently enhanced the reservoir management.
The data used within the paper comes from two different carbonate fields' of complex, heterogeneous pore structures, and diverse mineralogy, allowing generic approach to the drawbacks seen.
First MLTBS Level 5 Installation for Operator in Abu Dhabi
Authors: Elsayed Mohamed Ibrahim , Abdulhalim Abdallah , Al-Mutairi Ali Mohamed , Saqib Talha , Sabri Abdul Moez , Karrani Saud Mohamed , Ponton Calvin , Rosas Eulalio , ElSin Rami Samir 
Published: November 2016

Abstract
A major Abu Dhabi oil and gas producer targeted an increase in production from their major offshore oilfields. Better optimization of the reservoir through advanced well architecture was considered an option. One way to achieve this objective was through accessibility and hydraulic control of all horizontal drains. Multilateral technology is commonly used to increase the production per well and reduce drilling time while optimizing production facilities. The project targeted multiple reservoirs with two separate laterals to meet reservoir requirements. The application required individual through tubing access for intervention into each lateral. Multilateral technology has been traditionally limited to commingled production with limited or no access to the laterals. To help address and overcome these challenges, the operator planned and installed their first Level 5 multilateral tieback system (MLTBS).
Specifying CO2 Compressor
Authors: Desai Manthan G. 
Published: November 2016

Abstract

Objective / scope
This paper highlights the care to be taken by an Engineer while specifying and selecting a centrifugal compressor for CO2 compression.

Methods / Procedures / Process
With the increase in the levels of CO2 in the atmosphere, there is an increase in the popularity of capturing CO2 emitted from the large source points such as fossil fuel power plants, steel mills, cement plants, etc. before its release to the atmosphere and storing it under the geological formations (also used for Enhanced Oil Recovery (EOR) where possible). The compressors used to transport and store the CO2 at such depths need to compress the gas from atmospheric pressure to the pressures of the order of 200 bars or more.

Results / observations / conclusions
The critical temperature of CO2 is only 31.1 deg. C, so the CO2 is generally transported and stored in supercritical state. The thermodynamic properties of supercritical CO2 are considerably different from the other real gases generally compressed. Further, to achieve this supercritical state, the critical point of CO2 is crossed somewhere in the compression stage. Near critical point, the ideal gas laws will not hold good for CO2. Moreover there is a reduction in the choke margin of the compressor due to the reduction of the sound speed in CO2, particularly near the thermodynamic critical point. Also the CO2 compressibility and specific heats are not linear near the critical pressure and temperature. The impurities in the CO2 will further affect the thermodynamic characteristics of the working fluid. Also the water content in the CO2 makes it extremely corrosive.

Novel / Additive information
Considering all the aspects mentioned above, specifying the CO2 compressor correctly in terms of the equation of state to be used, the interstage pressures and temperatures to be maintained, suggesting the number of impellers per stage to maintain the desired flow coefficient, metallurgy to be selected and scheme of compressor dry gas seals, etc becomes all the more important and are described in the paper.
Unlocking Profitable Production Opportunities Based on Mature Common Field Proven Subsea Control Components
Authors: Elsabbagh Sameh 
Published: November 2016

Abstract
In deep water, subsea approach is often non debatable. Besides, subsea solutions are often selected because a platform-based development would not be profitable. However, due to very large combinatorial size of the design and operational decision space for the Platform versus subsea solutions, the selection between Platform and subsea solutions is a matter of doubt unless having large reserves or complex reservoir.
Based on experience acquired through various subsea gas projects, the paper outlines some standard blocks for subsea production system based on mature and field proven components. In this context, flexible architectures along with Tie-back options with existing infrastructure and its related de-rating will be illustrated. Subsea gas compression standard template solution along with its control system requirement will be overviewed. Key factors are highlighted in order to take sufficient account of options value. This will be very helpful for concept selection especially for stranded/ marginal fields allowing unlocking of new opportunities for profitable production where shallow water subsea systems can be an ideal solution for improving net present value.
Improved Workflow for Characterizing Complex Carbonate Reservoirs
Authors: Smart Charles , Mohnke Oliver , Bhatt Pranjal , Fernandes Warren , Salter Tim , Ping Tian , Jin Ou , Mohamad Faisal , Saeed Ismail , Hasani Majid 
Published: November 2016

Abstract
Understanding the hydraulic properties of reservoir rocks is crucial for estimating reserves or managing storage and production of a reservoir. In reservoirs containing complex carbonates, rock-typing methodologies that recognize multimodal porosity have been widely used. A new rock-typing workflow based upon Thomeer-buoyancy modelling is presented, with proven application in Middle Eastern carbonate reservoirs where multimodal porosity is observed.
Porosity reflects the total pore volume of the rock, but fluid transport within the media rock unit is dominated by the fractional pore volume connected to the largest pore throat system. The mercury intrusion capillary pressure (MICP) experiment alone provides insight into the connected porosity and permeability volumes. In addition, the MICP experiment establishes the relationship between the vertical saturation profile of the wetting and non-wetting fluid phases. A workflow that captures the buoyancy of the fluids (saturation-height) alongside this pore volume complexity can then provide insight into the pore geometry, saturation distribution and permeability of the investigated reservoir volume.
This workflow is distinctive because it integrates reservoir physics with new analytic approaches that include a routine conversion of properties from ambient to reservoir conditions, a fully automated Thomeer deconvolution of mercury injection experiments (THOPAL) and a Thomeer-buoyancy analytical solver for properties estimation in the log domain.
The solutions provided comprise continuous magnitude and category estimations of 1) permeability at reservoir conditions and Thomeer coefficients (G,Pd and Bv), 2) statistical uncertainties of the previous, 3) continuous scalar results in the hydrocarbon column including reservoir capillary pressure, bulk volume oil and Sw as well as probabilistic pore geometry grouping.
Two case studies are presented to demonstrate the application to wellbores within the investigated Middle Eastern carbonate reservoirs.
Ultra-Sour Natural Gas Sweetening Using Membranes/Amines Hybrid Systems for Recurrent Middle East Conditions
Authors: Alkatheri Mohammed , Grandas Ricardo , Betancourt-Torcat Alberto , Almansoori Ali 
Published: November 2016

Abstract
Recently an increasing number of countries have expressed their concerns over meeting their future gas domestic demands and export commitments. This tendency is particularly palpable in the Middle East countries. Thus, the region's gas producers have been compelled to develop unconventional ultra-sour gas fields previously considered uneconomic due to technical challenges. Conventional gas processing considers chemical absorption methods using solvents (such as an alkanolamine) for acid gas (e.g., H2S and CO2) removal. However, new polymeric membranes for bulk H2S removal from both very high H2S content gas and operating pressures have been recently developed. These recent developments can contribute to the treatment of unconventional ultra-sour gas or retrofitting existing plants. Accordingly, the present study analyzes a hybrid sour gas sweetening system consisting of two stages. In a first stage, a membrane system is used to reduce the inlet feed gas bulk H2S and CO2 concentrations. Consecutively, the sweet gas product final specifications are met using an amine-based system. Ultra-sour gas (e.g., 25% H2S) is considered to be treated. The study uses a simulation-based optimization approach. The proposed hybrid process was simulated using ProMax® v3.2. The ultra-sour gas conditions are uncommon on a global scale, but they can be found recurrently in the Middle East. The simulation results show that the operating and capital expenditures of the process can be reduced using a hybrid system.
Deciphering Intrinsic Fluid in a Low Salinity Sandstone Reservoir to Optimize Reservoir Management Development Strategies
Authors: Rabba Ali S. , Madani Sultan S. , Zeghlache Mohamed Larbi 
Published: November 2016

Abstract
Fluids identification in reservoirs that bear low or mixed formation water salinity poses a challenge for reservoir management in terms optimum well placement strategies and reservoir surveillance. The logging industry provides many technologies to help characterize in-situ fluids while drilling or during the production stage.
An integrated reservoir engineering team has established an integrated formation evaluation methodology to identify fluids encountered in the reservoir, while drilling or while monitoring saturation changes periodically in key observation wells. A number of new and re-entry wells were selected to measure fluid saturation while drilling via different saturation tools; namely, resistivity, nuclear magnetic resonance (NMR), formation pressure testing and fluid sampling, and advanced mud gas logging to complement each other. Carbon/oxygen (C/O), coupled with a flowmeter survey, were run in two observation wells, in both flowing and shut-in conditions, and showed positive results for enhacing the capability to monitor saturation.
Following a comprehensive evaluation of all acquired data and interpretation, the petrophysical model was calibrated using NMR and downhole fluid samplings. Results have enabled building fluid characterization criteria for low contrast salinity clastic rocks based on reservoir complexity and fluid uncertainty.
The optimized C/O acquisition helped with analyzing fluid saturations and building an intriguing process to address challenges related to different environmental conditions. This evolved methodology revealed a more consistent saturation mapping with the actual reservoir understanding while identifying the optimum completion and excellent wellbore conditions for such a method.
The established fluid identification process, while drilling, will help optimizing well placement and well completion to yield productive wells. The customized C/O log process will enhance reservoir surveillance and monitor saturation change to assess sweep efficiency and overall field performance.
An Effective Approach for Uncertainty Analysis and Workflow Optimization in Undeveloped Reservoir
Authors: Buzdar Mudassir , Ali Mohammed , Hussain Amjad , Arif Naveed , Bughio Shamsudin 
Published: November 2016

Abstract
Subsurface appraisal activities are employed to reduce reservoir uncertainties. Field appraisal/delineation is crucial to understand the subsurface complexity and define the extent of reservoir. In such scenarios, the ability to appropriately characterize reservoir is a primary factor that determines economic viability of a development project. The high cost associated with appraisals of petroleum fields requires manageable risk and uncertainty quantification. Often, results from appraisal campaigns are not enough to reasonably justify decision of developing the field.
An efficient methodology for quantification of subsurface uncertainties during the appraisal stage was implemented to frame the objectives for achieving optimum outcomes. The approach is more systematic in comparison to classical methods to gain better understanding of uncertainty parameters, capture level of uncertainty and identify optimal model for the field development. Production forecast using probabilistic approach provides good estimate of cumulative oil or recovery factor considering the impact of uncertainties and risk.
This study employs uncertainty quantification and optimization workflow for assisted history matching and forecast during appraisal stage. Uncertainty parameters with ranges and distribution, response parameters along with criteria set were framed into the workflows of sensitivity, history matching and uncertainty analysis. Experimental design techniques (OVAT and Latin Hypercube) were used for sensitivity analysis and uncertainty parameter reduction. Objectives set for scope of studies were driven with detailed analysis of the simulation runs and successfully culminated the promising results within specified project time duration.
The methodology is applied to onshore field in the Middle East during the appraisal phase with limited wells.
Benefits and Challenges of In House Engineering for an Operating Company
Authors: Balfaqih Mohamed , Kataria Ashwani , Farah Ahmed 
Published: November 2016

Abstract

Objectives / Scope
This paper will discuss how the In House Engineering Department, named Technical Centre – Engineering TC (E) within an upstream Exploration and Production (E&P) Company have managed to fulfill the duties of a design consultant and contributed to the long term development of young engineers.
Since 2014, the TC (E) has successfully conducted screening studies, conceptual designs and Front End Engineering Design (FEED) projects of various magnitudes up to 150,000 man-hours.

Methods, Procedures, Process
In terms of schedule optimization the in house engineering department has tremendously helped company projects in meeting its mandate because the tendering cycle usually associated with any project is not applicable. Furthermore, the engineers part of the in house department are company employees who are well aware about the company's requirements, the condition of the assets and in the best condition to add value from any lessons learned related to past projects. In summary, there is no learning curve as part of the projects implementation.

Results, Observations, Conclusions
The cost associated from conducting the In House Engineering is much less than if it will be tendered to an outside consultancy company.
Besides the cost and time benefits, performing the Front End Loading (FEL) Projects by In House Engineering have resulted in stronger compliance to the company's technical requirements since TC (E) are the custodian of the Company's Engineering standards, better governance because the Value Assurance Reviews are done by the TC (E) technical authorities, and more flexibility to project changes since scope variations can be agreed internally between Company departments.
Being a department within an operating company, though, is having its own limitations of fixed organizational structure, inability to promptly acquire resources based on project load and being bound by established tendering and contracting policies has created its own set of challenges. Furthermore, there is some specialized studies part of the conducted projects that needed to be tendered outside due to unavailability of software or expertise.
Though there are challenges in managing engineering activities in an E&P Company, the benefits outweigh these challenges. In-House Engineering is adding value to the Company business needs and provides a fit for purpose and cost effective engineering solutions.

Novel/Additive Information
The novelty of having an In House Engineering department within an E&P Operating Company is adding a value in terms of better resource utilization, cost optimization and compliance to company standards.