bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Alternative Polymers for Mangala Polymer Flood
Authors: Shankar Vivek , Sunit Shekhar , Zagitov Robert , Gupta Abhishek Kumar , Kumar Suresh , Kumar Ritesh , Pahari Kumarish , Agarwal Rahul , Nakutnyy Petro , Veerabhadrappa Santhosh 
Published: October 2022

AbstractMangala field is under polymer-flood since 2015. The polymer-flood is very successful in accelerating recovery compared to waterflood. As the flood matured, field performance indicated that part of the injected polymer was degrading in the reservoir. Lab studies and polymer samples collected from the reservoir suggest that the most likely reason of degradation is increased hydrolysis due to thermal ageing. This degradation compels higher dosing of polymer to make up for the lost viscosity and increases operating costs. Polymer precipitation in the reservoir may also lead to loss of reservoir permeability.Literature survey and preliminary lab studies showed that polymers with Acrylamide-Tertiary-Butyl-Sulfonic acid monomer units (referred as ATBS polymers) could be a suitable option for Mangala. To evaluate the hypothesis, team did a series of lab and core flood studies. The studies include accelerated thermal ageing, rheology, dynamic adsorption, injectivity, water flood with fresh and degraded samples and compatibility studies with topside chemicals. Two HPAM polymers with different DOH and two ATBS polymers were evaluated. The selected ATBS polymer was then tested for compatibility with surface topside chemicals.The studies show that the classic 20-25% DOH HPAM suffers viscosity degradation and possible precipitation in Mangala reservoir conditions. ATBS polymers and a lower DOH HPAM provide superior results to the incumbent HPAM with an acrylamide (86)-ATBS (14) copolymer providing the best results. ATBS polymers were especially resistance to cloud point lowering and provide some superiority in shear degradation. ATBS monomer was resistant to hydrolysis in the period of testing. Contrary to published literature ATBS polymers showed higher adsorption and their propagation through cores required higher pressure drop. ATBS polymer seemed to plug a low permeability section of the core stack. All polymers reach their peak viscosity at 30-40% hydrolysis and decline sharply after 40%. However, viscosity and cloud points measured during accelerated ageing are possibly conservative. A large-scale pilot of ATBS injection in Mangala is underway to validate the laboratory test results.ATBS polymer can be a suitable polymer for some layers of Mangala with high residence time and permeability. The choice is driven by the economics of the incremental cost of ATBS for the benefits it offers. In some sands with shorter inter wells pacing, a lower DOH HPAM may work out to be a more cost-effective solution.The study results provide insights to operators to understand the reservoir performance of existing polymer-floods and plan for future polymer-floods.
CO2 EOR Challenges and Opportunities to Enable CCUS Strategies
Authors: Pimenta Gervasio , Romero Carolina 
Published: October 2022

Abstract
This paper provides insights on the current challenges and opportunities associated with the development CO2 EOR projects as part of CCUS strategies. These projects are strategic for the oil and gas industry, not only mitigate the impact of GHG emissions from current operations, but also to enhance their oil recovery. The paper shares how lessons learned from ongoing CO2 EOR pilot projects in ADNOC Onshore have allowed the optimization of surface facilities, material selection for well completions and helped identify limitations to find solutions and proposals to deploy new technologies and enable CCUS strategies.
Since 2016, ADNOC Onshore has pioneered CO2 injection, both continuous and in WAG mode, using captured CO2 from Emirates Steel Industries under the Al Reyadah CO2 supply project (Sheikh, F, 2021; Hassan, S. et al 2021; Alklih et al 2019). Experience from the ongoing pilots was reviewed for potential cost optimization of the well design, while ensuring the same level of reliability and integrity of the completions from on-going Waterflood and HC WAG developments implemented in the same fields.
CO2 composition and fluid conditions were reviewed along with reservoir monitoring and log acquisition to study recommend strategies for WAG cycle changes that would mitigate potential corrosion issues.
Completions for CO2 WAG Injectors in ADNOC Onshore pilots have been traditionally applied in CRA material and employing wellhead heaters. These, represent high-cost elements in the drillex and CAPEX of WAG-CO2 development projects.
Results show that for WAG-CO2 projects L-80 1Cr materials may be used in WAG Injectors significantly lowering the Drillex costs. Mitigation strategies include the use of viscous fluid spacers that will limit the contact between CO2 and Water during cycle changes. Well head and down-hole temperature surveys showed that CO2 cooling effect under ADNOC Onshore field conditions was not a concern and long term injectivity has not been significantly affected. As a result, CO2 Heaters have been removed optimizing the CAPEX of on-going CO2 project studies
Field Development Simulation of a Mature Field with High Sealine Pressure and Well Eruptivity Issues
Authors: Koeck Charles-Henri , Agrawal Pawan , Goyal Praffula , Bensadok AbdelAziz , Madoz Alexis 
Published: October 2022

Abstract
Liquid loading is experienced in high water-cut wells operating against high sealine pressure in an offshore mature field without artificial lift. This phenomenon is usually not captured by VLP/IPR representation built into reservoir simulation or steady-state well models, which results in overestimation of future oil production. Key value drivers for the project are developing an understanding of the liquid loading based on critical fluid velocity, well completion and reservoir characteristics and study its impact on simulation forecasts.
Firstly, the liquid loading condition has been correlated to different well parameters such as productivity index, GOR and water-cut. The correlation is built from routinely acquired flow test data showing wells ceasing to flow due to unstable flow regimes and fluctuating sea line pressures. Additionally, extensive well modelling using Prosper software was carried out to assess the proper fluid correlation method. Secondly, that correlation was converted into a response surface model to make the link between the unstable flow regime conditions and the impacting parameters such as well PI, GOR, well geometry. Thirdly, the unstable flow correlation was implemented in the simulation model with a script of conditional events in order to flag wells with unstable flow and shut them if no activation condition is applied such as artificial lift or THP reduction.
Currently, it is estimated that about 4 wells are becoming unable to flow every year due to the mentioned loading issues. These loaded wells require vessel/barge to carry out unloading which involves significant operating cost in an offshore environment. This complex behavior is normally overcome by dynamically coupling the subsurface models to the surface production system. However, in a giant field with hundreds of wells from multiple reservoirs this can be complex and resource demanding.
Application of the correlation in the simulation resulted in about 80 wells with unstable flow conditions to be closed by year 2040, whereas they would have otherwise continued to flow if regular VLP curves were used. This method served to improve the model accuracy and to increase the assurance in forecasts predictability, with regards to water-cut evolution.
This study was a key driver input for deciding on the acceleration of a major debottlenecking facility related to medium pressure system at surface. Sustainability of field plateau, improved wells availability, reduced in-active wells count and associated reactivation resources are tangible benefits of the mentioned study.
Fiber Optic Surveillance for Water and Polymer Conformance Monitoring in an EOR Project in Petroleum Development Oman
Authors: Al Hashemi Mohammed Salim 
Published: October 2022

Abstract
The focus of this paper is to elaborate on the decisions taken based on the information obtained from the FO data in lab and field tests in polymer and water flood projects. It aims to provide insight into how Fiber Optic (FO) data through both Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) can be used to quantify in-well injection conformance for both water and polymer. The data was analyzed collaboratively between Shell and PDO and used to build a robust workflow to generate an inflow profile for either the water or polymer phase. Also, it has been used to assess Out-of-Zone injection, matrix versus fracture injection, and to prove conformance & injectivity improvement after acid stimulation. The output from FO compares favorably with other reference data such as PLT.
The paper will go through different aspects of workflow development covering all the methodologies used to convert FO data to inflow profile in flow rate. It will also provide information on how the obtained knowledge from this pilot can be replicated throughout various fields in and outside of Oman. The Fiber optic surveillance strategy for polymer flood has truly proven its value ready for potential upscaling for similar polymer projects.
FO data was acquired from permanent fiber installed behind the 7″ production casing from water and polymer injectors in a field in the South of the Sultanate of Oman. A total of 14 DAS and 9 DTS surveys were acquired in 7 water injector wells followed by additional 4 DAS surveys in polymer injectors wells. DTS data were acquired during several injections and shut-in periods to measure the warm-back transient conditions before full stabilization to (pseudo) geothermal temperatures. Data were processed and analyzed using a thermal simulation model to allocate and quantify injection conformance per zone. DAS data were acquired during injection with a minimum of three flow rates. The data were processed, time-averaged, and filtered to specific frequency bands to identify injection conformance.
The Method of Directional Radial Drilling of Channels for Stimulation of Oil Rims
Authors: Galas Ilya , Bashirov Ayrat , Makarenko Vitaly , Miftakhov Salavat , Lyagov Ilya , Dolman Lee , Gulyaev Danila , Nikonorova Anastasia 
Published: October 2022

Abstract
This paper presentsan effective EOR solution for the development of oil-rim deposits. A case history is presented where production from a mature field with low permeability terrigenous reservoirs and nearby water and gas-cap was recovered without the drilling of new infill wells. Fracking in such conditions was not appropriate due to the close proximityof the gas cap. Directionalradial drilling was used to accurately drill four channels in the required azimuthal directions before slotted liners were deployed in each channel to control solids production.
The directional radial drilling technology is unique and creates channels with a diameter of 69 mm (2-3/4") and a length of up to 25 m (82 ft.) through the identified target zone in the reservoir. The special bottomhole assembly (BHA) is deployed on jointed pipes using a standard workover hoist. The stimulation method drills up to 4 hyper-short-radius channels from the same TVD, and formation evaluation measurements can be taken in each channel. Slotted liner or screens can also be deployed if required. This technique is ideal for thin low permeability reservoirs of any type.
A candidate well was identified and four channels with a diameter of 69mm (2-3/4") were accurately placed at the same TVD along a pre-set trajectory in a radial pattern up to 14 m (46 ft.) per channel using a BHA with a mud motor. The planned-versus-actual trajectories were confirmed by a directional survey. A sand screen was deployed in each channel to control produced solids. The resultant performance of the target reservoirs was evaluated by the results of logging (inflow profile). An 898% increase versus the pre-operation production rate was achieved. A production rate with a liquid flow of 673 bbl. per day and an oil flow rate of 252 bbl. per day was obtained. Further reductions of water cut from 56% to 1% during clean-up, and the oil production rate was increased to 598 bbl. per day from the original 60 bbl. per day. The longevity and value of this EOR method is demonstrated by &gt;16 months decline rate to return to initial production rates. The experience demonstrates that the technology is a very valuable stimulation method where gas cap and/or underlying water create challenges to conventional stimulation or infill sidetracking.
This was the first occasion this unique Directional Radial Drilling EOR technology was applied on an oil deposit in a terrigenous reservoir. Additionally, this was the first-time the radial channels were linedwith sand screens. The operation performed has proven that the technology of directional radial drilling is an extremely valuable EOR stimulation technique for oil wellswhere standard hydraulic fracturing is restricted. This technique is valid for and applicable to all reservoir types.
A World First Innovative Hybrid EOR Pilot in a Giant Carbonate Reservoir in Abu Dhabi : Pilot Design and Field Deployment
Authors: Bhushan Yatindra , Igogo Arit , Al Baloch Shahid , Al Blooshi Mohamed Abdulla , Khan Sara Hasrat , Chappell David , Brodie James , Al Tenaiji Aamna , Al Ali Mona Yousif , Xu Siqing , Masalmeh Shehadeh 
Published: October 2022

Abstract
Simultaneous injection of miscible gas and polymer (SIMGAP) has been proposed as a technique for improving sweep efficiency of miscible CO2 in a giant heterogeneous carbonate reservoir (B) with harsh conditions of high temperature and salinity in Abu Dhabi. A pilot is planned to evaluate the concept. Reservoir simulation models were built to design the pilot and to evaluate field-scale deployment of SIMGAP, assuming the pilot is successful. This paper describes the pilot design and the workflow used to assess large-scale deployment.
Reservoir-B comprises of two main units, Upper and Lower, which are in hydrodynamic equilibrium but have large (10-100) permeability contrast, due to which, water injected into the Lower unit rapidly crossflows into the Upper unit bypassing significant volumes of oil in the Lower unit. Hence, the Lower unit forms a key target for enhanced oil recovery (EOR).
In the SIMGAP process, miscible gas (CO2) is injected into the Lower unit and polymer solution is simultaneously injected into the Upper unit. Provided the polymer solution generates sufficient resistance to flow in the Upper unit, crossflow of CO2 is suppressed, and the Lower unit is efficiently swept by miscible CO2.
A SIMGAP pilot has been designed, consisting oftwo central 3000-ft horizontal injectors for polymer injection in Upper, and CO2 injection into Lower unit respectively and two 3000-ft horizontal producers in the Lower unit 250m from the central injectors on either side. Reservoir sweep will be determined by repeat logging of vertical observation wells and the polymer solution in the Upper unit will be sampled to confirm in situ viscosity.
A reservoir model was built and calibrated to field behavior to design the Pilot.The relevant design parameters include offtake rate, polymer and CO2 injection rates, polymer pre-flush and polymer solution concentration and viscosity. A key prerequisite for proper modelling of SIMGAP is to have a static model that captures the geological heterogeneity (e.g., vertical permeability contrast, all prevailing rock types) and a dynamic model that incorporates the SCAL derived capillary pressure (both drainage and imbibition) and relative permeability curves. The model forecasts show that significant sweep of the lower zone is achieved with SIMGAP compared to both water or gas injection and that the process is stable and robust to lateral and vertical reservoir heterogeneities.
The SIMGAP process has never been piloted and it involves a hybrid of two EOR techniques CO2 injection and polymer flooding in harsh conditions of both high temperature and salinity. In addition, field deployment of SIMGAP was directly simulated in the sector models. The resulting field profiles were used to evaluate SIMGAP deployment in Reservoir-B.
Drilling in Area of Unstable Shallower Formations Prone to Rig Pad Subsidence: Turning the Impossible to Possible
Authors: Zahoor Ullah Syed , Ruzhnikov Alexey , Al Fakih Abdulqawi 
Published: October 2022

AbstractSome of the oil and gas fields in the in Middle East are prone to a shallow sand subsidence while drilling conductor and surface sections, which may result in the in cellar and surrounding area to subside. In the worst case scenario, it may lead to a well abandonment. This issue is known locally as a cellar subsidence or sinkhole and carry high severity risk. Considering the out of proportion risk, drilling engineering team of project formulated an out of the box solution with enough contingencies to cope with this risk and drilled subsequent wells successfully.The task of sinkhole prevention and mitigation plan was divided in three phases. In first phase, its risk level was identified by generating a risk identification map of the field after analyzing almost all the wells (more than 500 wells) drilled. After identifying with help of this map that sinkhole risk exists mainly in specific areas, temporary plan was not to drill in this high-risk area of +/- 2 km2. However, it left this area of the reservoir undrained which was not acceptable to reservoir development.As neither leaving the area of the field undrained nor abandoning the wells due to ground subsidence was sustainable, the task was taken to the next phase to formulate a plan to make the drilling possible in this area or similar areas in this field or other fields. As such based on investigative analysis of all the previous incidents, the engineering team proposed a structural approach for an innovative and vigorous plan along with risk assessment and complete scope of contingency measures. This included pilot hole drilling, changing drilling fluid system, drilling parameters, identification of early signs of the risk, changing casing seats, utilization of casing while drilling and a pre-defined strategy to optionally cure losses based on depth of losses. Following the identification of the structure of the plan, a detailed procedure with specifics on fluid properties, expected rock behavior during drilling, detailed contingencies and flow charts were developed.With this plan, subsequent wells were drilled with 100% success, in high risk zone of sinkhole where the plan was further updated with lessons learnt on well by well basis.This unique technique which included more than one measures targeting each specific aspect of cellar subsidence mechanism, is adopted for the first time. Considering its success rate, it can be adopted in any other project, where similar situation is faced.This paper provides of details including mechanism of sinkhole, severity of risk, conventionally attempted unsuccessfully prevention attempts, newly developed strategy followed by its successful applications and lessons learnt.
Implementation of Advanced Bit and BHA Design Software for Drilling Performance Improvement in Offshore Abu Dhabi
Authors: Yudhia Denya Pratama , Choudhry Bilal Iftikhar , Singh Roopinder , Salas Juan Del Alvarez , Rabis Philippe , Couzigou Erwan , Al-Marzouqi Adel , Al Ameri Fahed Salem , Ayadi Mohamed Selim 
Published: October 2022

Abstract
This paper seeks to address the challenges of BHA dysfunctions in complex wells’ environment which impacted the drilling performance in Abu Dhabi Offshore. Drilling operations experienced various cases of BHA failures, which triggered the need for advanced tools to enhance the bit and BHA design analysis during the well preparation phase. Market research was conducted to identify the commercially available software for bit and BHA design analysis. It is to enable a systematic in-house analysis of the bit and BHA proposed by the service providers to ensure the directional drilling and performance goals can be achieved. A specific drilling software was identified as a fit-for-purpose solution. It offers 3D mechanical modelling of any directional system, sensitivity analysis on multiple BHA settings, hole characteristics, and operational parameters driven by a fast-numerical methodology. The acquired software package includes several key modules: BHA pre/post-analysis, PDC bit model, local doglegs, and vibration analysis. The plan was then put in place to enable implementation across fields. In-house training was conducted to introduce the software to end users. Data gathering for PDC bit and RSS modelling was conducted in collaboration with the service providers. The BHA pre-analysis workflow was then defined to enable comprehensive bit and BHA modelling analysis, covering directional drilling analysis and vibration modal analysis. An agreed BHA configuration and stabilization was identified, and boundaries of optimized operational parameters were determined. Drilling operation was then executed with the agreed bit and BHA following the recommended operating parameters. In after, the BHA post-analysis was conducted to calibrate the PDC bit and RSS modelling by utilizing real-time data and directional drilling information. It also captured the lessons learned for bit and BHA design future improvements. The workflow was implemented for 22 drilling BHA in 2021 with most of the focus in 6″ hole section, long lateral drain application. The BHA performance evaluation of the 6″ hole section demonstrated the improvement result, with 10 out of 12 BHA achieving the objective to complete the section in 1 run. The BHA specific polar plot and RPM driller roadmap provided in this analysis functions as a practical guide for BHA analysis during well preparation and execution.