bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shuaiba Lagoon and Basinal Facies Exploration Potential in Abu Dhabi
Authors: Taher Ahmed , Celentano Maria , Franco Bernardo , Al-Shehhi Mohammed , Al Marzooqi Hassan , Al Hanaee Ahmed , Da Silva Caeiro Maria 
Published: November 2018

Abstract
In early Aptian times, subtle tectonic movements may have been activated along the NW-SE strike-slip faults and have resulted in a vertical displacement along these faults. The displacement would have allowed the carbonate-producing organisms to colonize along the shallower southern margin and generate well developed reservoir facies. The basinal facies were deposited to the north of the shelf margin, which is known to be the Bab Basin.
Significant oil was discovered in the Shuaiba shelf facies. However, the lagoonal and basinal facies have potential for discovering a significant volume of hydrocarbon, especially in the fields that are located in the Upper Thamama hydrocarbon migration pathways. This potential is supported by the absence of an effective seal separating Thamama Zone-A from Shuaiba basinal facies above, which allowed for the Zone-A hydrocarbon to migrate vertically into the Shuaiba basinal facies. In addition, this potential was supported by the hydrocarbon shows while drilling and by the interpreted well logs, which confirm the presence of movable hydrocarbon in the Shuaiba lagoonal and basinal facies.
The Shuaiba Formation is comprised of two supersequences (Azzam and Taher, 1995, van Buchem et al., 2010 and Lyndon et al., 2010) that were deposited during the Aptian time. The lower sequence started at the early Aptian time and mainly included Hawar Member, Thamama Zone-A, the Shuaiba shelf facies and its time equivalent Shuaiba basinal facies sediments. The second sequence was deposited after the drop in sea level below the Shuaiba shelf break. This drop caused subaerial exposure of the Shuaiba shelf platform and allowed for the clastics material to influx the fine-grained over the Shuaiba basinal facies area. The clastic influx and the carbonate rich claystone of the Late Aptian sequence sediments may represent the effective top seal for the Shuaiba basinal facies and Zone-A oil accumulation.
The Shuaiba basinal facies were deposited in an intrashelf basin that was enclosed by the Shuaiba shelfal facies sediments. This resulted in restricted water circulation, anoxic condition and deposition below the wave base. Such depositional environment is favourable for source rock preservation.
Lithologically, Shuaiba basinal facies consist of pelagic lime-mudstone, wackestone and packstone with abundant planktonic microfossils. These facies are characterized by low permeability values, but their porosity can reach up to 20%. The lagoonal sediments consists of a deepening sequence of carbonate sediments, with shallow marine algal deposits at the base and fine hemipelagic to pelagic carbonates in the upper section.
The differences between the Shuaiba Shelf and the Shuaiba Basin are mainly in permeability values. By applying the latest technology in horizontal drilling and hydraulic fracturing, the Shuaiba basinal facies will produce a significant volume of hydrocarbon.
Boosting Condensate Recoveries of a Mature Retrograde Gas-Condensate Field in Pakistan
Authors: Ahmed Sheraz , Khakwani Atta , Ahmed Ijaz , Daud Farrukh 
Published: November 2018

Abstract
One of the most challenging part of managing a Gas-Condensate reservoir is to reduce Condensate Banking and its damaging impacts on the overall recovery. Several techniques have been applied in the past to overcome this problem such as pressure maintenance by Gas Injection (i.e. Lean gas, CO2 or N2), Water-Alternating-Gas (WAG) or chemical injection etc. However, none of these techniques could easily be initiated on a mature Gas-Condensate Field owing to the large upfront CAPEX and technical limitations. This study presents a strategy on such a mature Gas condensate reservoir, to target the Condensate banks and improve the overall condensate recovery.
This study has been based on a field currently producing from the Potwar basin of Pakistan. The current pressure of the field is around 2500 psi - significantly lower than the Initial Reservoir Pressure (5200 psi) and Dew point (4950 psi). The PVT reports are showing that the reservoir has already passed the region of Maximum Liquid Drop out (MLDO). Thus, there was a risk of losing a good amount of Condensate if proper measures were not taken.
This study focuses on the strategy to target these Condensate banks being accumulated at different locations of the Field, which has given an increment of around 30% already in the condensate production rates. Since the reservoir pressure has already dropped considerably below the dew point pressures - conventional CO2 or Lean gas injections cannot be utilized as they require significant re-pressurization which is technically and economically impossible at this stage of field's life. In this study, an alternative approach taken, is presented which increases the overall condensate recovery by almost 90%. This includes drilling smartly placed production wells (at locations which were not very attractive in the start of field development) and the overall impact of placing the injectors for Selective Water Flood using comprehensive reservoir simulation and water flood algorithms.
This paper illustrates the approach that can be utilized in a mature gas condensate field where no pressure maintenance has been performed since the start - to improve the overall condensate recovery. This paper presents a clinical analysis of targeting the Condensate banks and possible usage of selective water flood strategy to sweep these banks along with the optimum placement of wells and injectors. This offers an innovative approach towards such gas condensate fields which are facing the problems of condensate drop out and re-pressurizing the field to a higher Reservoir pressures, at current stage, is next to impossible.
Offshore and Marine: Challenging Offshore Installation Tactics and First Float Over Installation Accomplishment in Cheleken Field
Authors: Joshi Rajeev Padmakar 
Published: November 2018

Abstract
The Caspian Sea is the largest landlocked sea between Asia and Europe with its own pros and cons. The enormous reserves in Caspian has created great opportunities for Oil and Gas operators and their partners (Service and EPIC Contractors). The design and installation of offshore structures have been always inspiring for structural designers and naval architects. In the past decade, various installations have been successfully completed using different techniques based on the availability of marine vessels & cost dynamics.
This paper provides insights about challenging techniques used for various installations including Topside float over keeping focus on Safety, various technical aspects and cost effectiveness right from detailed engineering to installation phase.
Considering availability of marine heavy lift vessels in the region and their day rates considering the constraints with the Volga-Don Canal size, the following methods/Designs were developed and implemented: The jacket was divided into two parts (lower and upper). Each portion weighing approximately 400 mt (metric ton) were installed one above the other with locator mechanism to maintain lower CAPEX. This was mainly due to non-availability of heavy lift vessels.Similarly for another project, during detailed engineering phase an "Intermediate Support Frame" was introduced by adjusting jacket and deck module height."Hydra-Lok connection technology" was used for pile sleeve strong connectivity. This was mainly to avoid any welding and grouting requirement.For the float over, unique LMU (Leg Mating Unit) were fabricated in Caspian and Transportation barge was assembled in Caspian region with capacity to launch 4,000 mt jackets and install 6,000 mt topsides.
These customized installation techniques have helped in achieving required timely project completion and thus meeting production targets. For other conventional installations, available crane barges with smaller lifting capacity were used for facilities/ modules installations.
This paper further addresses the technical issues and challenges emphasising intricacy and effectiveness of the technology used.
The development of novel systems described in 1, 2 & 3 above are most suitable for Caspian region, with more focus on float over installation systems as well.
The achievements till date has paved ways for future optimised and safer designs and float over method has added a feather in Cheleken area resulting in early completions of projects at reduced CAPEX.
The Development of Economical Clamp to Repair Expansion Piping in Regeneration Gas System
Authors: Nokjib Schach , Pewkliang Suppachai , Theeradechphuwadol Thas 
Published: November 2018

Abstract
The objective is to study and develop the economical clamp to use for leakage repair caused by pipe crack at piping supports in gas regeneration system, which is operated under thermal cyclic condition and not possible to call the ad-hoc plant shutdown window.
The process of this study is to analyze the thermal expansion of piping and clamp, which is a cause of the gap at contact surface between 8″ piping and clamp. The clamp design is developed with understanding the influence of heat conduction as well as the material expansion.
The experiment has been setup to verify the clamp design in the scope of performance and endurance test. The expected end result is the efficiency of clamp to secure the pressure while gas leakage is occurred under thermal expansion effect.
The result from design, development and experiment to prove its performance and endurance is indicated that this ecomomical clamp is in good condition and can secure the pressure under gas leakage situation. This project now generates the benefit to preserve production and sale (prevent unplanned plant shutdown), prompt response (perform as an emergency repair) and very low fabrication cost (able to reduce fabrication cost for 40%, approx.). It's not only for one operating asset, but for all and for company as the whole business units. Besides, it's potentially to continue the design development in various sizes of piping operated under thermal cyclic condition. It much more commercial in the following day.
In the monetary aspect, earlier (from 2014 until now), company has to bear with the Lost Production and Sale Opportunity for 12 million USD from unplanned shutdown caused by gas leakage at piping crack nearby pipe support in regeneration gas system, which is operated under thermal cyclic condition. From the loss occurred, it compells company to study and develop effective emergency response plan and equipment to prevent the loss and control the risk from the piping leakage issue in the gas regeneration system.
Thermal Degradation Kinetics of Epoxy Resins and Their Drilling Application
Authors: Al-Yami Abdullah , Wagle Vikrant , Cuello Jimenez Walmy , Jones Paul 
Published: November 2018

Abstract
Epoxy-resin applications in oil and gas wells have significantly increased for remediation and sustained-casing-pressure mitigation because of its solids-free nature and excellent thermomechanical/bonding properties when used either as a single component or as a resin/cement-enhanced composite. Therefore, it is imperative to assess the formation and degradation of structures in cured epoxy resin at downhole temperatures, particularly because hydrocarbon production requires long-term wellbore integrity.
Differential scanning calorimetry (DSC) was used to determine the glass transition temperature (Tg) of the proposed resin system, and thermogravimetric analysis (TGA) was used to characterize the thermal degradation response by monitoring the resin specimens’ mass loss over time under controlled temperatures ranging from 300 to 680°F at atmospheric pressure. The thermal kinetic response based on TGA was then modeled using the Arrhenius equation to predict the resin lifetime under expected wellbore conditions. A uniaxial load frame Tinius Olsen tester was used to assess the mechanical response of the resin system under elevated temperatures.
For a resin system subjected to downhole temperatures of 263°F, the model predicts that reaching 10% mass loss by thermal degradation can take more than 160 years, which is beyond the operational life of the wells where the system is evaluated. This indicates that the investigated resin system provides long-term dependability that ultimately results in reduction of intervention/remediation costs, along with production maximization. Additionally, the resin mechanical properties were evaluated at different temperatures to assess their response to expected thermal loading, which resulted in competent barriers that can withstand the cyclic loads generated by continuous wellbore operations. This work also presents a case study in which an epoxy-resin-cement composite is used as an annular barricade to help prevent and reduce sustained casing pressure. The resin-cement composite was placed in the annular section as a chemical packer tailored to improve bonding to steel pipe, along with optimizing its mechanical response to cyclic downhole loads, which resulted in no up-to-date sustained casing pressure. Furthermore, Cement Bond Log (CBL) results further support the optimum annular integrity attained when utilizing a cement-resin composite as chemical packer for enhanced isolation and annular pressure buildup mitigation.
A Comprehensive Study of Wellbore Stability in Laminated Carbonate Rocks by Nuclear Magnetic Resonance Experiments
Authors: Kesserwan Hasan , Guodong Jin 
Published: November 2018

Abstract
To counter the consequences of the wellbore instability problems, a thorough analysis of the borehole conditions is performed throughout the entire life-cycle of a hydrocarbon well from planning during the early stages to completion and production. The analysis comprises the following: first, a rigorous understanding of the rock properties e.g. geochemistry and geomechanics mainly the stress magnitudes and rock strength. Second, the mud properties and the entailed interactions with the formation. For instance, numerous borehole failures in laminated rocks have been attributed to the interaction of the drilling/fracturing fluid with the layered-matrix e.g. interaction of water-based-mud with reactive clay minerals.
This paper focuses on the impacts of the pore fluids redistribution on wellbore stability in organic rich carbonate rocks. The experimental method consisted of measuring the Nuclear-Magnetic-Resonance transverse relaxation time (NMR T2) on samples saturated by spontaneous imbibition of oil and brine. The wellbore stability was investigated by analyzing the changes in the NMR T2 distribution of each sample after imbibition sequences. The obtained results demonstrated the elevated impacts the wettability and pore structure characteristics on the spatial distribution of the fluids in these rocks. The type of clay content in the bedding planes and its consequent interaction with the drilling mud was identified as a potential driver of the rock instability problems. The discrepancies in the wetting traits were magnified by the presence of fractures that enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space.
Unconventional Solutions to Address Slope Protection Issues
Authors: Narasimhan Thirugnanam , Adel Khalid , Al Maskari Juma 
Published: November 2018

Abstract
Protection of bunds and slopes is of prime importance in Oil and Gas facilities, in order to contain hydrocarbon products and to protect soil erosion. This paper highlights some slope protection challenges and mitigation techniques comparing the conventional systems and describes the evaluation methodology including Sustainability and Cost optimization potential of a new material "Concrete Impregnated Fabric". The knowledge obtained in determining the evaluation criteria and methodology of this slope protection system is worth sharing with industry professionals.
Conventional slope protection involves mainly gatch and concrete lining. While the design life of gatch being less, use of reinforced concrete is non-sustainable. The main challenge in slope protection is "slope stability" involving the type of soil to be retained and slope angle. Various polymeric products named as Geo-strips, Geogrids, etc. are used for soil reinforcement. Steel mesh surrounded Gabion retaining structures are used for retaining very high slopes. New technologies such as "Mastic grouted mattresses" are more suitable for sloped surfaces of coastal areas.
"Concrete Impregnated Fabric" or "Geo-synthetic Cementitious Composite Mat (GCCM)", a new material that hardens on hydration was found suitable for quick construction and has many more advantages. Technical evaluation criteria and detailed evaluation process in selecting this slope protection system is described in this paper. Technical information, features and installation methods of the product have been collected from the manufacturer and subjected to a detailed desk study. After initial review, the product with its varying thicknesses was applied on mock-up bund, demonstrating laying, joint-fixing, end-anchoring and initial hydration. This event has been witnessed by more than a dozen of engineers from all plants of ADNOC Gas Processing. The trial site was left exposed to atmosphere and revisited after 6 months and the condition ascertained.
Physical properties listed in the information brochure have been verified by carrying out third party laboratory tests in UAE based on various international codes and witnessed by professional team. Also as part of evaluation process, in a pilot project, it was applied on pipeline bund area of about 4000 Sqm.
Apart from the sustainability aspects and techno-commercial analysis, other advantages of the product such as design-life of 50 years, construction ease, 24% cost saving compared to concrete lining and feedback from previous users, etc. were evaluated and captured in a comprehensive report based on which it was accepted for use on slopes without any loads. Evaluation of this fit-for-purpose slope protection system including its pilot application will be useful for all relevant stakeholders.
Modeling Rate of Penetration for Deviated Wells Using Artificial Neural Network
Authors: Abbas Ahmed K. , Rushdi Salih , Alsaba Mortadha 
Published: November 2018

Abstract
The advanced technology has made directional drilling widely used to enhance the production of mature fields. The rate of penetration (ROP) contributes strongly towards the cost of drilling operations, where achieving higher ROP leads to substantial cost saving. The main objective of this study is to develop a model that predicts the ROP for deviated wells using artificial neural networks (ANNs).
The model was developed based on the most critical variables affecting ROP using ANNs. In addition to the azimuth and inclination of the well trajectory, the controllable drilling parameters, unconfined compressive strength (UCS), pore pressure, and in-situ stresses of the studied area were included as inputs. 1D Mechanical earth modeling (1D-MEM) data, geophysical logs, daily drilling reports, and mud logs (master logs) of deviated wells drilled in Zubair field located in Southern Iraq were used to develop the ANN model.
The results displayed that the ANN’s outputs are close to the measured field data. The correlation coefficient (R) and average absolute percentage error (AAPE) were over 0.91 and 8.3%, respectively, for the training dataset. For testing data, the developed model achieved a reasonable correlation coefficient (R) of 0.89 and average absolute percentage error (AAPE) of 9.6%. Unlike previous studies, this paper investigates the effect of well trajectory’s (azimuth and inclination) and their influence on the ROP for deviated wells. The major advantage of the present study is calculating approximately the drilling time of the deviated well and eventually reducing the drilling cost for future neighboring wells.
A Case Study on the Effect of Production Segmentation Completion Technique PSCT and Inflow Control Devices ICD on the Optimization of Horizontal Well Performance
Authors: Alshmakhy Ahmed , Abdalla Ruaa 
Published: November 2018

Abstract
Horizontal wells have been drilled extensively in recent years where several challenges have been faced such as increased cost, short well life, limited accessibility, uneven stimulation, less productivity and water production. Although similar issues encountered in all reservoirs, tight reservoirs impose extra difficulty given their complexity and inherited limited productivity. In order to optimize flow profile and extend the life of horizontal wells, several techniques were implemented including Production Segmentation Completion Technique (PSCT) and Inflow Control Devices (ICDs).
Initially, a single well simulation study was conducted to determine and evaluate the effectiveness of using a dual completion string and ICDs in a horizontal well with open hole across a carbonate reservoir which generally suffering from rapid increase of water-cut due to high drawdown around heel. A review of literature and internal well cases were conducted to highlight the heel to toe effect and early water breakthrough issues.
As a result a novel multi-zones completion technique was proposed and implemented, this design comprises running a lower completion (LC) as isolation string and an upper dual completion, the hole heel will produce from the open hole (OH)-LC annulus through the short string (SS) and the toe will produce through LC through the long string (LS) stung-into LC. This design provided a method to choose the most appropriate horizontal section and demonstrated the value of having dual completions in terms of oil gain and water management as well as improved accessibility. This approach is then compared with the option of utilizing ICDs as a sophisticated method to control flow and manage production from different compartments of the openhole.
Field results supported the success of segmented completion project providing future opportunity to optimize the production configuration of horizontal wells. Thus, reducing number of wells and increasing production. Execution of this project increased production by about 1.3x versus single completion well, accessing deeper horizontal areas, with an optimized cost in addition to saving time. On the other side, inflow control devices were used extensively in industry with a large chance of success when planned well. On the simulation model, ICDs were added and different sensitivities were tried to decide on the best configuration.
Implementation of such optimization tools in early stages may be crucial to mitigate potential well issues that are difficult to cure later in well life. This complex and high profile project was executed against a background of limited time frame and resources. Project team demonstrated ability to adapt and succeed when presented by a truly unique challenge. A comparison study was essential to decide on best approach. To date, PSTC technique is the first to be implemented in UAE and the Middle East.