bluuebunny/crossref_metadata_2025 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

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

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

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

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

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

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

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

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

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.
Application of Wormlike Micelles for Mobility Control in Chemical Enhanced Oil Recovery
Authors: Kumar Sandeep , Kalwar Shuaib Ahmed , Abbas Ghulam , Awan Abdul Quddos
Published: November 2018

Mobility control is one of the most important parameters in chemical enhanced oil recovery (CEOR). Hydrolyzed polyacrylamide (HPAM) polymer, the standard mobility-control agent, is often degradable and causes poor sweep efficiency under changing shear rates and at temperatures above 140 °F. Under these conditions, HPAM solution loses more than 90% of its viscosity and is unable to sustain appropriate viscosity necessary for residual oil displacement. Therefore, a wormlike micellar (WLM) solution was developed as a substitute mobility polymer for CEOR applications. The WLM solution is composed of chains, bonded by electrostatic forces, which can deform and reform rather than permanently breaking down when subjected to high shear rates and temperature fluctuations.

In this study, two compositions of WLM solutions were chosen and prepared in the laboratory. For each of these two solutions, their effectiveness was determined by comprehensive thermal compatibility tests; interfacial tests (IFT); and rheological tests to evaluate the impact of concentration, shear rates, salinity (NaCl = 3.5%, CaCl2 = 0.05%, and MgCl2 = 0.05%), and temperature (86 to 158 °F) on viscosity. Next, the core displacement test was performed to examine the residual oil displacement by a mixed-surfactant WLM solution (zwitterionic surfactant 1.09% w/v, R = 0.55).

Test results determined that both of the tested WLM solutions showed great potential in high-salinity and high-temperature conditions. Each of the two WLM solutions was equally adaptable and unrestricted, despite differences between the components of each formulation. With the addition of salts, the WLM solutions were highly tolerant over the entire range of shear rates. At 158 °F, the thermal degradability of WLM solutions was less than HPAM polymer. In addition to this, IFT between crude oil and WLM solution was also observed to be very low compared to the typical water-and-oil system. Moreover, the WLM solution produced an additional oil recovery of 10.9% beyond secondary recovery during the coreflooding test. Hence, the results supported WLM solutions to be potential mobility control for CEOR.

WLM solutions have been successfully shown to perform beyond the salinity, temperature, and shear-rate limitations of HPAM polymers. This makes WLM solutions more flexible, not only for EOR applications, but also for well completion, well stimulation, and for coiled-tubing cleanout processes following gravel-pack operations.
Reservoir Health Indicators Driving Performance Through Data Analytics
Authors: Al Marzouqi Mohamed , Saputelli Luigi Alfonso , Abdou Medhat , Narayanan Ram , Mohan Richard , Ismail Ayat , Escocia Alvaro
Published: November 2018

Reservoir management leverages on surveillance practices to diagnose reservoir conditions which aid in the identification of treatments that maximize the business value of reservoir deliverability while protecting the long-term sustainability. However, operators struggle to exploit value from data because of big data avalanches, data dispersion and ambiguity in the data definitions across department and companies.

Typically, operators are satisfied by meeting average targets within certain tolerance. This is obtained by calculating the ratio of plan vs actual performance. In this work, reservoir management excellence is pursued by an integrated review of leading and lagging indicators, which are represented by continuous and proactive KPI computation and monitoring.

The objective of this work is to simplify reservoir performance data analysis on such a way that performance management is decomposed in 5 key areas (business, operation, quality, recovery and predictability) driving continuous improvement, and yet establishing a culture of variance reduction and sustainable consistency in results delivery.

The scope of this work entails the definition and case studies of implementing performance indicators that facilitate the analysis of reservoir performance and field development strategic decisions. Such indicators are leading pointers of quality, recovery status and predictability, which ultimately affect business and operations performance at multiple time scales.

A solution to continuously compute reservoir health indicators and assure reservoir performance is implemented across various assets, leveraging big data management with automated scheduled extraction, transformation and loading (ETL) capabilities. Raw and calculated data are further provided to end user via commercially available business intelligence (BI) analytics. Each indicator measures the compliance between actual and planned values, and the roll-up is done by computing the volume-weighted average of each underlying element. For this purpose, key performance indicators (KPI) are calculated and creatively concatenated from well to reservoir level, from reservoir to field level and from the field to the operating company level.

KPI rollout showed a new way to report and monitor performance on a proactive, sustainable and cost-efficient manner. Some of the realized benefits included reducing more than 90% the time require to identify variances between actual performance and expectation during the execution of projects and improving compliance to the reservoir management guidelines from ~61% to ~84%. This ensures long-term production sustainability while mitigating shortfalls proactively.
Sub Seismic Fault Identification within Carbonate Reservoirs with Borehole Images Logging-While-Drilling: Integrated Approach in Optimizing Well Placement; A Case Study from Offshore Abu Dhabi
Authors: AL-Hassani Sultan Dahi , Ahmed Shafiq Naseem , Khan Owais Ameer , AL-Tameemi Ibrahim Mohamed , Khan Shahnawaz , Marza Philippe , Abdulrahim Jaja Uruzula , Shasmal Sudipan , Alexander Malcolm
Published: November 2018

Reservoirs located offshore Abu Dhabi can be complex in terms of sub-seismic structural features such as faults and localized deformations. With use of high-resolution resistivity image logs, a TST (true stratigraphic thickness) technique, along with 3D structural models, uncertainties related to sub seismic structural ambiguities are resolved and well trajectory is optimized while drilling.

In this case study, real-time resistivity image logs were used while drilling. The sinusoid’s shape on images provided cutting down dip or up dip information. Dip trends were analyzed using a dip vector plot and to identify zones-of-interest. Dip attribute along with the log response were compared with the pre-job model and the inclination is adjusted accordingly during drilling. Several high angle features can be characterized as stratigraphic changes, fractures, or faults. The morphology and trend change observed in the dip vector plot of these features lead to the conclusion that these are sub-seismic resolution faults and deformation is associated with the fault.

The stratigraphic drilling polarity and the TST were calculated using the formation dip data. Using a TST scale and splitting the logs into stratigraphic drilling polarity domains, the fault throw displacement is estimated. The model is updated to reflect the interpreted data. The fault plunge and trend are extrapolated away from the wellbore and to nearby wells.
Novel Scavenger Technology for Effective Removal of H2S from Produced Gas in Oilfield Applications
Authors: Ramachandran Sunder , Lehrer Scott , Chakraborty Soma , Jani Jagrut
Published: November 2018

Hydrogen sulfide (H2S) scavengers are used to reduce the total well operation cost of working with H2S by reducing the need for gas sweeting equipment, manpower costs for H2S monitoring, fines due to out of specification production and liability due to H2S release. Commonly used H2S scavengers such as triazine and glyoxal have limitations in different applications. When overspent, triazines can form difficult to remove solid deposits. The prescence of triazines in crude oil can lead to the formation of amine hydrochloride salts that cause corrosion in refinery operations. Glyoxal based H2S scavengers are acidic and can cause corrosion especially in stagnant pipelines containing oil and water. In this paper laboratory and field results are provided on new H2S scavengers that are both non-amine and neutral pH. The applications that are examined are batch tower applications and inline injection.
ADNOC Gas Processing Experience in Hydrocarbon and Acid Gas Flare Recovery Utilizing Liquid Ring Compressor and Dry Screw Compressors
Authors: Ramasamy Babu
Published: November 2018

The gravity of this paper submission is to intimate and share that ADNOC Gas Processing, a group of ADNOC (Abu Dhabi National Oil Company) launched and implemented recently a considerable number of flare gas recovery projects like Habshan Hydrocarbon Flare Gas Recovery, Habshan acid gas flare recovery, Habshan-5 Hydrocarbon Flare Gas Recovery, Habshan-5 acid gas flare recovery and Habsha-5 flash gas recovery with great success.

The purpose of these projects is to recover low pressure hydrocarbon and acid flare gas, compressor and inject into gas network for further downstream processing before converting it to sweet gas for sale or use for other applications.
Integrated Asset Modeling Assists Brownfield Rejuvenation
Authors: El Faidouzi Mohamed Mehdi , Al-Katheeri Walaa Anees , Fathalla Magdy Farouq , Bedewi Mahmoud , Kedia Rachit
Published: November 2018

An integrated asset modeling (IAM) approach was used to evaluate a reinvigorated facilities configuration for a mature giant oilfield offshore Abu Dhabi. The field has produced for 50 years through steel jacket-based "supercomplex" facilities. A new artificial islands-based strategy has been envisioned to cater to higher production requirements, replace ageing facilities approaching their design lives, and debottleneck the water and gas handling capacity.

Commercially available reservoir simulation software was used to develop the integrated reservoir simulation model. The IAM fully couples three compositional simulation models for each reservoir unit to an extensive pipeline network and incorporates the timely rerouting of existing facilities to the new processing centers. Eventually, the "supercomplexes" only receive wellstream fluids from the existing wellhead towers (WHTs) network and redirect production to the new centralized processing island where it goes through a three-phase separation. Recent pressures and production data were used to calibrate the IAM.

The IAM was successfully used to evaluate the impact of the new surface layout on production. The production profiles from the standalone models, based on constant terminal node pressure at the wellheads, were compared to the IAM profiles. Pragmatic guidelines were defined to obtain representative profiles from the standalone models. Additionally, the IAM was used to guide the future facilities design by addressing the sizing of the water and gas handling capacity and identifying future surface bottlenecks. Moreover, the compositional IAM allowed quantifying the H2S content in the stream. The reservoirs being drained have varying levels of H2S, and prediction of the gas sourness is an important parameter for separator and pipeline design and for determining the sale gas value. Finally, the IAM had flow assurance applications, such as assessing the changes in pipeline temperature. Indeed, as the field matures, wells are forecasted to produce more water, raising the field water cut from the current 7% to 20% in the next 10 years. This increase in water cut would increase the pipeline temperature. The IAM allowed forecasting of the steady-state pipeline temperature to ensure existing pipelines are operated within specifications and to help design future flowlines.
Corrosion Management, Field Trial Results of High Pressure Black Bimodal PE100 HDPE Liner in a Super Gigantic Field Provides Innovative Strategy for High Pressure Water Injection Flow Line Internal Corrosion Management
Authors: Amabipi Abby Kalio , Salem Marwan Hamad , Grandhe Siva Prasada , Gupta Tijender Kumar , Awah Mohamed Ali , Schell Jeff , Compton Ted , Herbig Nicholas
Published: November 2018

Objective

Internal corrosion in high pressure water injection flow lines is a very serious problem in the ADNOC super gigantic onshore fields. This issue has resulted in frequent pipe leaks and water injection flow lines outage which adversely affected oil and gas production due to failure in meeting the required water injection. This paper illustrates successful cost efficient innovative application strategy of the HDPE Liner technology in mitigating internal corrosion problems in water injection flow lines.

Methods

Innovation centers of some petrochemical companies have now made available "BIMODAL PE100 POLYETHYLENE" materials which are suited for high pressure pipes and able to provide extra flexibility and safety in case of surface scratches in highly deviated flow lines. This paper presents the detailed preparation of the HDPE material, installation, intensive monitoring program, results and integrity challenges of the technology validation in 3km pipeline. A rolling machine reduced the OD of HDPE liner by 7% before drawing into the flow line by a pulling machine, the HDPE OD expands back to full size to give a tight fit in the flow line after sometime.

Results

The field trial was initiated in June of 2011 and actual installation completed in two weeks. The Liner conditions were monitored from 2011 through 2017. The flow line section protected with HDPE liner still operates in excellent conditions without any sign of corrosion up till date. This is a technology break through that eliminated internal corrosion threats with huge Opex savings in chemical treatment programs as no chemicals were applied. This Technology is now at the implementation stage in the ADNOC super gigantic onshore field.

Novel

The paper elaborate on the value added to the company and possible areas of application of the technology for maximum benefits. Finally, this technology has clear impact on the internal corrosion management process that guarantees proper flow line long-life innovative design strategy and provides alternative solutions to conventional flow line designs.
Feasibility Analysis and Field Application of Waste Oily Sludge Resource Utilization Technology in Oilfield
Authors: Wang Yao , Wang Siwen , Li Rui , Wang Hao
Published: November 2018

Oily sludge is one of the main wastes produced during oilfield development. The composition of oily sludge is complex, resulting in difficult separation and high processing cost. The existing technologies such as landfill, microbiological deterioration, heat treatment and solvent extraction are difficult to meet the needs of oily sludge treatment. It is necessary to develop a highly efficient and cheap reutilization technology for oily sludge. For this reason, we have proposed to recycle the oily sludge which can be utilized to profile control in water injection and thermal recovery wells.

In the process of research, we have developed five aspects of work: First, three-phase separation of oily sludge was carried out by distillation, and water quality, oil-phase composition and solid particle size were analyzed. The compatibility of oily sludge and oil reservoir was investigated. Second, the mechanism and influence factors of the oily sludge for profile control were studied by long core model test and microscope observation. Third, suspension analysis and mobility analysis were developed on oily sludge, and experimental results were used to research oily sludge profile control agent. Fourth, numerical simulation was used to optimize the engineering design of Oily Sludge Profile Control (OSPC). Fifth, ground process flow of oily sludge for profile control was designed.

The following conclusion can be drawn from the study: OSPC is a Reutilization Technology for oily sludge, which could seal up oily sludge in-situ in oil reservoir and be favorable for increasing production of oil wells through profile control. Through the rheology and plugging test, it was clear that OSPC could greatly reduce the pollution risk of oily sludge and the ground treatment cost, and solid phase and oil phase of mud were retained in the formation. It could plug high permeability channels and high permeability area (the plugging rate was more than 90%) to adjust water/steam injection profile of water/thermal recovery wells. Profile control agent, engineering design method and ground process flow for oily sludge were developed. The technology applied 72 wells in the oilfield, 184 thousand tons of oily sludge were used in total, production of crude oil was increased by 84 thousand barrels, and a lot of sludge treatment costs could be saved.
Precision Gas Sensing Based on THz Spectroscopy
Authors: Assefzadeh M. Mahdi , Jamali Babak , Babakhani Aydin
Published: November 2018

In this work, we introduce a spectroscopy system based on an electronic source that can radiate terahertz frequency combs to perform broadband spectroscopy of trace gases. A single-chip source provides us with a highly compact and cost-effective system in comparison with a laser-based source, and a faster response time in comparison with chemical sensors. We have performed THz gas spectroscopy using three different gases, H2S, NH3, and H2O. These measurements have been performed at 575, 736, and 754 GHz.
Challenging ICD & Swell Packers Completion Running in 3D Complex ERD Well With Continuous Swiveling to Break Frictional Drag and Helical Buckling
Authors: Singh Rudra Pratap , Paila Phalgun , Al-Kindi Rashid Khudaim , Al-Wahedi Khalid Ahmed , Kirby Cliff , Blakely Michael , Christie George
Published: November 2018

Extended Reach Drilling (ERD) from the artificial island is particularly challenging for anti-collision, directional drilling and wellbore construction; facing various issues including but not limited to wellbore instability, hole cleaning, tortuosity, torque and drag etc., affecting the completion liner running and its ability to reach the setting depth especially in the smaller hole sizes. This paper describes the application of ground-breaking technology that enables completion liner with multiple ICDs and Swell Packers to be deployed at setting depth in ERD well maximizing oil reservoir production and saving cost.

In 3D complex well profiles, while running conventional completion liner string, frictional drag is cumulated along the string, exposing the same to sinusoidal buckling which is further elevated to helical buckling and consuming the load available from surface to transfer to shoe, ultimately preventing the string to reach the setting depth. The buckling is even more severe in smaller hole sizes like 6" hole section where tapered drill string with 4" DP against 7" liner is used to run lower completion.

By allowing a portion of the string to be rotated, significant amount of axial friction is converted from drag to torque and provides additional hookload at surface to push the string to TD. This selective rotation is enabled by the integration of a Swiveling Tool into the string above the Liner Hanger. The tool has been tested in a development well in an artificial island of offshore Abu Dhabi. This was the longest well drilled by operator with measured depth of 24,414 ft (Horizontal departure +/− 20,000 ft, 6" drain hole length +/− 5,200 ft).

Later this technology was implemented in most of the challenging 3D complex wells and the Swiveling Tool became part of completion running string (4-1/2" Liner with ICD's and swell-able packers) based on the T&D simulation results if they indicated very little or no margin of drag available prior to string lock up which might make it impossible to reach setting depth.

This paper describes a structural approach towards running 4-1/2" lower completion with ICD and swell packer in 3D-complex ERD well utilizing swiveling tool to ensure completion is run to the desired setting depth. The proposed tool can be implemented any project worldwide where buckling could prevent running lower completion and there is restriction to rotate the lower part of completion or if there are chances of having obstructions due to hole condition/geometry.
Correlation Between Drilling Parameters and Lithology - The Hidden Geological Information of Drilling Data
Authors: Lamik-Thonhauser Bouchra , Schoen Juergen H. , Koller Christian S. , Arnaout Arghad M.
Published: November 2018

Drilling process is fundamentally controlled and influenced by the properties of the penetrated formation. The focus of various studies is directed mainly on the optimal design of drill bit and drilling operations related to the (expected) geological situation of a safe drilling process.

Out of interest the question "Is it possible to extract any lithologic information from drilling data?" also arises.

The drilling process at the bit represents a complicated rock mechanical process. The drill bit acts as a rotating cutter, controlled mainly by weight on bit (WOB), bit size, number of revolutions per time (RPM), which controls speed of the cutting process. We define a "cutting force Fc" as a combination of these parameters and investigate the relationship between Fc and rate of penetration (ROP). For the correlation with lithology of penetrated formations, two methods are applied on test wells:

– crossplots Fc versus ROP with discrimination for dominant lithology. – histograms of the ratio of two variables for dominant lithology.

Drilling data from two basins are analyzed (in both cases wells are nearly vertical):

– Vienna Basin: Dominant lithologies are sandstones (varying degree of cementation), shale/marls, limestones, and dolomites. – Williston Basin: Dominant lithologies in the analysed section are sandstone shale, dolomitic limestone, and limestone with anhydrite.

Data points from the rocks with similar lithology in the crossplot are situated in a cloud - different rocks show different cloud position. Particularly between clastic (sand, silt, shale) and carbonate (limestone, dolomite) rocks, a clear separation is visible.

The implementation of lines for a constant ratio Fc/ROP in the crossplot separate the different lithologies. Therefore, the statistical distribution of this ratio S = Fc/ROP for the dominant lithologies was analyzed by histograms. For the two test wells, histograms separate the different lithologies and confirm the information content.

The drilling process is controlled by rock type; the analyse of drill-process data can be used for a lithological discrimination and especially for detecting changing lithology (boundaries) during drilling process. For two test wells, the discrimination could be demonstrated by the crossplot and histogram technique. The exact position of discriminator magnitudes (center of data clouds in the crossplots, peaks in the histograms) is specific for the considered field and may be controlled by more drilling parameters.