bluuebunny/crossref_metadata_2025 huggingface dataset:
Completion Design and Hydraulic Fracturing Evolution in a Tight Reservoir Having Low Poisson's Ratio and Low Young's Modulus: A Case Study in Aishwariya Barmer Hill (ABH) Oil Field, Rajasthan, India
Authors: Bohra Avinash , Vijayvargia Utkarsh , Tiwari Shobhit , Gupta Sumit , Kothiyal Manish Dutt
Published: October 2022

Aishwariya Barmer Hill (ABH) field is a moderate permeability (0.5 – 4 mD) oil bearing porcellanite with alternating sequences of tight shale. After successful appraisal campaign a full field development with multi-stage fracturing using cemented frac sleeves, field was brought online with Hydraulic Sucker Rod Pump (HSRP) as artificial lift and has been on production since 2019.

However, a need was felt to review the frac and completion design on account of challenges faced during fraccing and unplanned downtime during production operations. Critical observations that prompted a change in completion and frac technology are: Formation rock pebbles and proppant were observed in the wellbore during workovers.Reservoir's low Young's Modulus (YM) allows the generating high strains at low pressures, while low Poisons Ratio (PR) makes the rock brittle and shatter under high deformation. Consequently, shattered rock was not able to hold the proppant in place after fracture closure resulting into flowback of proppant and pebbles.Debris fill in wellbore resulted in production impairment and malfunctioning of HSRP.

To mitigate the identified risks, the design change incorporates measures to address post fracturing production problems related to high treating pressures as well as optimize number of frac stages and stage spacing. Uniform proppant distribution with lesser number of stages is targeted by utilizing limited entry technique to help in distributing treatment pressures and proppant in multiple clusters as well as limit net pressure build up in each frac. It will help prevent rock shattering and better retention of proppant after frac closure.

Completion design workflow includes log based zonal isolation between each stage and frac design for two to three cluster per stage. The revised design will predict the number of stages in each well for optimal utilization of wellbore for best economical production.

Revised frac design has been implemented in 5 infill wells wherein 66 stages have been pumped without TSO signature or premature screen out in any of the stages. Wells have been put on production and are performing better than rest of the wells in the field. There has been no evidence of debris accumulation in wellbore or proppant flowback in production fluid. Further drilling campaign for 15 wells has been planned with cluster frac strategy with revised frac design.
Using Hybrid Geosteering to Proactively Position a Well in Fractured Tight Carbonate Jurrasic Rock – A Middle East Deep-Gas Reservoir Case Study
Authors: Al-Mutawa Majdi , Bloushi Taha , Al-Ajmi Saad Abdullrahman Hassan , Al-Bader Fahad Khned , Pattnaik Chinmaya , Pasaribu Ihsan Taufik , Keot Chandan Jyoti , Osman Salih Noreldin , Siam Mahmoud , Basset Mohamed Abdel
Published: October 2022

Deep, unconventional tight carbonate reservoirs in northern part of the Middle-East present many challenges for field development. These challenges are due to the inherent very low porosity characteristics with an average 2 to 6% matrix porosity and 0.01 to 1.5 mD permeability. Natural fractures play a primary role in the producibility of these reservoirs. High angle well is being planned as a way to intersect as many fracture systems as possible for production improvement.

To better visualize the subsurface structure while drilling, Ultra Deep reservoir mapping while drilling was deployed to map the whole reservoir boundaries in real time and know the formation dip and precise trajectory position from reservoir roof and base at any point in the lateral section. The 3D reservoir mapping gives precise geological geometry of the reservoir and enhances the placement of the well. The information from Reservoir Mapping While Drilling integrated to other downhole measurements such as Near bit Gamma Ray, Resistivity and the surface logging of gas composition and geo-chemical data could help immensely to determine the productive fracture zones.

The foremost drilling challenge in deep Jurassic carbonates is exposure to high borehole temperature which can go up to 300 degF, due to high friction factor at depths of more than 12000 ft vertical depth from sub-sea (TVDSS), combined with high temperature gradient. This downhole high temperature environment almost reaching LWD tools maximum temperature thresholds, could potentially affect the LWD tools while drilling because of excessive fatigue to the electronics.

This paper will discuss the case study of well placement challenges in deep Jurassic tight carbonate reservoirs and solutions to ensure of the success of the well operation and achieve well objectives.
New Technological Possibilities to Perform On-Stream Monitoring of HTHA
Authors: Putintsev Sergey , Lens Herman
Published: October 2022

High Temperature Hydrogen Attack (HTHA) is a phenomenon that has become a center of attention for operators of chemical, petrochemical and fertilizer plants after several incidents in the recent years. These incidents have forced the industry to reconsider the scope of non-destructive testing and the inspection approach, and revealed a vital necessity for better prediction and monitoring. Recent technical developments are making it possible to perform HTHA inspections in-service (on-stream) during operation in addition to the traditional inspections during a shutdown. This creates a favorable opportunity to monitor early stage HTHA, which would allow asset operators to optimally utilize their assets without concessions to integrity and safety.
Agile Development of Machine Learning (ML) for Conventional Artificial Lift Systems in the Middle-East
Authors: Ajmi Ahmed , Andrade Antonio , Vargas Luis , Mackay Angus , Al-Busaidi Mahir , Al-Kharusi Faris , Azri Ahmed
Published: October 2022

The majority of Oman's southern fields are produced by beam-pumps which consist approximately 2,000 wells, globally beam pumps remain an extremely popular choice for secondary lift. Identification and diagnosis of beam pumps using dynocards is an expensive human visual interpretation process. It does not only require significant labor time but also requires deep expertise in the production technology domain. The development team had three goals: 1) use open-source analytics, 2) develop a Machine Learning application (ML) to solve business challenges and finally 3) foster solutions with significant value investment ratio (VIR). In this case, a proof-of-concept application was developed to automatically screen beam pump dynocards and identify abnormalities (e.g., electrical related failures) which cause improper operation of the well, leading to deferment, undetected by conventional monitoring systems, and/or mechanical damage.

To address the above challenges, an analytics minimum viable product (MVP) was developed for pattern recognition which significantly assisted in automating (analysis of a 100 hundred wells with real-time data in less than 1 second) the visual interpretation process, increasing efficiency, and reducing maintenance activities due to missed early diagnosis. It detects current and future abnormal conditions that cause improper operation of the artificial system to deferment and potentially to mechanical damage. This new app identifies and highlights these wells so that operations & maintenance staff can focus their attention where it is really needed, improving their workflows and decision making.

This paper outlines how applying Machine Learning (ML) along with the Scaled Agility methodology enabled the operator to develop an MVP and diagnose abnormalities on daily basis not raised by any other system. Of the 100 wells in the selected field around ~10% were identified with clear failures. This translated to approximate ~5 % improvement in lead indicator (prior to issues) detection projecting ~2.5 million USD in efficiencies and deferment reduction.

The cost of development in CAPEX was 0 USD as the team developed this purely on Open-Source platforms that were license free and on their own without the need of third-party application or resources.
Dynamic Fatigue Life and Integrity Monitoring in Novel Mobile Spiral Intelligent
Authors: Minto Chris D.G. , Stevenson Andrew
Published: October 2022

Evidence from initial deployments of the Hydrogen optimized Mobile Spiral Intelligent Pipeline (MASIP) with built in distributed fiber optic sensing is discussed to show the benefits of an integrated approach to pipeline integrity management. This offers not only conventional monitoring (leak detection, right of way protection) but also dynamic pipeline strain with a meter-by-meter residual life assessment that has the potential to improve the effectiveness and reduce the costs of physical inspection methods.
Vibration and Steam Leaks Monitoring Using a Batteryless IIoT Powered by Waste Heat Using LoRaWAN Wireless Protocol in Chemical Plants
Authors: Aragones Ortiz Raul , Oliver Parera Maria , Malet Munte Roger , Marquez Garda Maria Teresa , Comellas Vogel David
Published: October 2022

This work presents a novel waste heat-powered long-range wireless and battery-less industrial Internet of Things device (IIoT). It is conceived to measure and predict machinery vibrations and steam leaks. This self-powered and autonomous device will help energy demanding industries (chemical, petrochemical, oil refineries, paper, iron&steel, etc.) to become more environmentally friendly and profitable in their digitalization transition towards Industry 4.0 paradigm. Moreover, thanks to being continued powered by thermoelectric generators they are battery-less, enabling long-range wireless protocols adoption such as LoRaWAN, minimizing in-house wireless infrastructure, and incorporating edge computing. This capability allows to reduce up to 98% of the cloud computation effort and its GHG emissions contribution due to data can be computed inside the IoT device. These capabilities are tough to find in battery-powered IoT due to their battery lifetime limitations.
A Novel Approach for Improving Water Injection Performance in Oil Field by Applying Lean Six Sigma
Authors: Al Ghafri Zaaima Sulaiman , Al Mandhari Sulaiman Saad , Al Aamri Ghusun Amur , Al Zaabi Yousuf Salim
Published: October 2022

Objectives/Scope

Water injection (WI) is very critical in Oil Fields to improve pressure build up; hence maximizing oil recovery and increase volume.

In X field in South Sultanate of Oman, Water Injection is a key factor to stabilize Oil production. In 2018, rapid pressure decline has been seen in oil producing wells. Since then, a clear decline is seen in water injector wells which resulted in Oil lost up to 100 m3 of Oil per day.

Methods, Procedures, Process

To arrest WI decline, a ‘Lean Six-Sigma’ study was carried out using the DMAIC (Define, Measure, Analyze, Improve & Control) approach. The DMAIC approach is a proven improvement approach in global industries successfully utilized outside of Oil and Gas for number of years, but never utilized in this context until now.

The application of this approach helped significantly to enhance and reduce the defect, decline and variation, of the injectivity process. The DMAIC approach helped the team to understand the problem, analyze it and identify the root cause of the injection decline, to reach an optimized solution which is replicated across the field.

Results, Observations, Conclusions

The study showed that, due to the reservoir having low permeability and porosity, even a small amount of TSS (Total Suspended Solids) in the formation can have a significant negative impact on well injectivity. As a result, optimized acid stimulation was recommended for X wells until water is treatment facility is on stream by end 2023. A new acid recipe showed a lower defect, decline and variation in injection rate trend for the piloted WI wells. This had a significant improvement on X field injection and acceptance for the water and hence increase overall production and sustainability of pressure support across the field.

The results have proven that, by using this structured approach, the unwanted variation in injectivity and the level of process defects were reduced significantly which resulted in major oil gains.

Novel/Additive Information

Using this novel Lean Six-Sigma approach to improve injection managed to obtain the following impressive results on increase in Oil gain by 25 m3/day (9.8k/day $) 3.6 Million $ / Year.

Along with the impressive oil gain, this study will provide opportunities to many organizations for healthier and enhanced implementation of Lean Six-Sigma projects for Water Injection issues in Oil and Gas Fields. Furthermore, it has opened new era to the way similar problems are tackled.
Advancements in CO2 Membrane Separation Technologies: Reducing Emissions and Enabling CCS
Authors: Choudhury Tanzim Ahmed , Mahley George , Sanghani Pinkesh , Kumar Hans
Published: October 2022

To overcome production restraints caused by CO2 and H2S in mature basins, operators require more cost-effective gas treatment to effectively remove these impurities from natural gas. Cellulose triacetate (CTA) based CO2 separation membranes have already been used extensively in acid gas treatment and associated enhanced oil recovery. A new technical challenge was to provide a horizontal membrane element that could easily replace poorly performing existing flat-sheet spiral-wound membranes with minimal operational changes to debottleneck existing hardware capacity, minimize hydrocarbon loss, and reduce membrane replacement frequency. Existing CTA vertical hollow fiber CO2 separation membranes were further developed and modified into the form of 8-in./8.25-in diameter horizontal packaging.

Qualification testing was performed at an in-plant gas test loop using full-scale membrane elements. Test programs included varying inlet parameters such as feed gas pressure, temperature, and a wide range of CO2 concentrations. Results showed that the horizontal configuration of the hollow fiber gas separation membrane exhibited superior separation characteristics in terms of gas throughput and hydrocarbon retention in the sales gas, when compared to alternative currently available CO2 removal membrane technologies. The robustness of the membrane polymer was confirmed throughout several startup and shutdown scenarios, with stable gas flux and selectivity observed during rigorous and long-term testing.

The membrane elements can be deployed in existing installations as a "drop-in" solution to overcome production constraints, whilst driving down the cost of excessive membrane replacements. In brownfields, more efficient acid gas removal and enhanced hydrocarbon recovery will reduce emissions by lowering gas flaring and limiting the potential release of methane. Upfront capital expenditure and ongoing operational expenses in greenfield projects can be significantly reduced by the greater natural gas treatment capacity per membrane compared to alternative membrane solutions. The high-purity CO2 permeate stream can also support the implementation of carbon capture and sequestration (CCS), thereby helping to reduce the assets carbon footprint and overall emissions.

The advancements in horizontal CTA membranes have been proven in operation at several facilities, where they have improved the economics of the assets via reduced hydrocarbon flaring and increased gas throughput. An intelligent, automated digital membrane monitoring tool has been developed and deployed to further optimize membrane operations. Operators have also been able to actively pursue acid gas fields previously considered uneconomical for production. Such greenfield and brownfield case studies will be presented as part of this paper.
The Failure Predictive Index, an Algorithm that Exposes Pre-Failure Conditions on Electrical Submersible Pumps
Authors: Bermudez F. , Shono M. , Alnahhas N. , Letan M. , Yazdani H. , Almubarak A.
Published: October 2022

As one of the most widely used artificial lift methods, ESPs represent an important target system for failure prediction tools. Statistical analyses of ESP failures show that their frequencies vary considerably as multiple factors affect these pumps’ running life including reservoir characteristics, handled fluids, presence of solids, presence of free gas, and even improper design & installation.

Due to the variety of completion configurations, manufacturers specifications, and operating conditions under which ESPs are operated around the globe, the most practical approach to predicting their failures must be one that uses features built exclusively on real time data from sensors, independently of manufacturers specs and field conditions such as fluids and reservoir characteristics.

The Failure Prediction Index (FPI) algorithm presented in this paper uses specific proprietary features to differentiate the behavior of data during normal operation from the behavior patterns that have been detected in the days and weeks preceding such failures.

By displaying a single number between 0 and 1 on each calculation cycle, the trained FPI model presents the degree of correlation between the current behavior of the field sensors’ data and those whose patterns have been created from the failures during the training of the algorithm.

A number of wells where the FPI has been successfully implemented in pilot projects, has demonstrated the accuracy of the algorithm to predict failures. This tool is continuously trained with every new deployment on a project, field, and/or reservoir. Its algorithms are constantly refined, and its operating boundaries redrawn, providing the industry with an exceptionally useful tool for failure prediction and for adding true value only possible through the capabilities of Artificial Intelligence.
Two Decades of Mangala Field Journey - Key Highlights, Learnings and Recommendations
Authors: Prasad Dhruva , Singh Aditya Kumar , Shekhar Sunit , Kumar M Suresh , Pandey Amitabh
Published: October 2022

The Mangala field in India was the first major oil discovery in the Barmer Basin having a STOIIP of nearly 1.3 billion barrels in multiple stacked fluvial reservoirs. It contains medium gravity (20-28 °API), waxy, viscous crude (9-17 cP) in high permeability (1-25 Darcy) clean sandstone reservoirs.

The field was discovered in 2004 and brought online in 2009, one of the fastest from discovery to production phase. Hot water injection was started within few months of first production to sweep and maintain pressure. The hot water was essential considering wax appearance temperature (59 degC) close to reservoir temperature (65 degC). The hot water is also used as power fluid for jet pump (main lift system in field) and for annulus circulation in case of shutdown to avoid oil congealing. Jet pump application is the largest in the world with ~160 active wells lifting ~400,000 blpd reservoir liquid with ~500,000 bbls of power fluid.

Plateau production of 125k bopd was achieved within 14 months from production start, which is one of the fastest among large onshore fields. The initial average oil rates in wells were ~2000-15000 bopd. Given the high well productivity, the field plateau rate was revised to 150k bopd within a year of achieving 125kbopd.

Due to adverse mobility ratio with water, EOR screening and lab study was started right after discovery. Chemical EOR was identified as the most suited with polymer in the first phase followed by surfactant-based flood. Considering the EOR importance, a 5-spot polymer pilot was started almost simultaneously with the start of the field production. Basis pilot results, full-filed polymer flood was started from 2015 which is again one of the fastest EOR implementations. The polymer flood is one of the largest in world with 165 tons/day polymer consumption through ~500000 bwpd of polymerized water injection. Polymer flood reversed the production decline and is expected to give ~8% incremental recovery of STOIIP (~100 MMbbls) by 2030. Following polymer, a successful ASP pilot was conducted in the same wells/pattern which resulted in 20-25% incremental recovery of pilot STOIIP over polymer flood. Planning for large scale ASP implementation is underway.

There have been several challenges and important learnings along the way including vertical conformance, areal VRR management, polymer development, degradation, viscosity and quality control over time, jet pump and ESP operations etc.

Mangala field recovery has been quite fast with ~37% recovery within 13 years field life. Multiple infill campaigns have been conducted with ~280 wells drilled over 165 base development wells.

The paper presents the development journey of Mangala from discovery to date with key achievements, many firsts, learnings and recommendations based on waterflood and polymer flood performance for other similar fields.
Investigations in Separator Modelling & Performance in ADNOC, Utilizing Equation of State (EOS) Fluid Models
Authors: Hoda Mohammad Faizul , Asarpota Jyotsna Deepak
Published: October 2022

The objective of this paper is to share the results of investigations carried out in the area of separator modelling and performance within the context of ADNOC's Integrated Capacity Model (ICM). Field production from wells is collected via multiple sets of remote degassing stations (RDS) or towers to a centralized separation facility where single or multiple separators allow the separation of the lighter components (contributing to a gas stream) from the heavy components (contributing to the oil stream). We share the investigation results on the following areas related to this separation:

Range of pressure and Temperature of 1st stage separators Range of feed (field/asset) compositions & contributing well compositions Effect of separation performance of streams ExclusiveIn presence of other streams Effectiveness of using pseudo k-values in separation performance compared to full EOS separation Use of EOS based approach to production back allocation Comparison of GOR correction methods

The primary method used is the performing of simulations with an Equation of State (EOS) model. For the purpose of this study, the single EOS model developed for ADNOC's Integrated Capacity Model (ICM) is used. This model has 15 components and their associated properties. The relative molar content of each component (i.e. the composition of a stream) determines its behavior. The difference in behavior is due to the difference in compositions of streams originating from the various fields/reservoirs/wells. An off-the-shelf software package dedicated to fluid modelling with an EOS is used, with automation, to efficiently execute the EOS computations for thousands of streams. This type of automation is necessary for the purpose of this investigation.

The paper depicts the range of compositions from different assets/fields and shows the impact on the range when the streams are aggregated. The paper also shows result of investigation on the efficiency and separation of components in the gas or oil stream if a single well is routed through a separator and when the same well is commingled with other wells. The use of k-values for the separation of streams and their accuracy is also demonstrated in this paper.

Novel/Additive Information: A methodological investigation into the performance of separators and the use of k-values in the use of EOS-based production allocation solutions is presented. Secondly, the difference in well stream separation performance when done individually and when in combination with other well streams is computed.
Enhancing Upstream Oil Water Separation Efficiency Through Microwave Energy
Authors: Alamoudi Saeed M. , Alwani Mohammed Abdo
Published: October 2022

The objective of this paper is to showcase the innovative method for the dehydration of wet crude oil using a novel gravity separation vessel and associated systems in upstream gas oil separation plant. The new configuration uses microwave radiation along with other conventional separation methods such as chemicals, heat and electrostatic coalescers.

This new technique is intended to be used to tackle major and chronic issues associated with the operation of wet crude handling units that can lead to overall facility production bottleneck and reduced capacity. This issue is common in aging oil fields in which water-oil ratio increases and tight emulsions form. As a result, meeting oil product specification requires major facility upgrade and capital investment that could be difficult to justify. In order to avoid costly upgrades, the addition of microwave energy assisted water separation to existing gravity dehydrator vessel, along with upstream heat exchanger, electrostatic coalescers metallic grids and demulsifer injection is being considered. Microwave electromagnetic radiation offers selective treatment of water molecules when designed for operation in 840 MHz or 2.4 GHz frequencies. This is due to dielectric constant being lossless for oil at selected frequencies while being lossy for water, resulting in high energy dissipation in the form of microwave induced movement of water molecules. To further enhance separation, Faraday cage made from metallic mesh is employed to focus microwave radiations in targeted area, which in our case is the oil-water emulsion area. The mesh structure is also designed to maintain laminar movement and prevent interferences with electrical signals from electrostatic coalescers. Finally, control scheme is also going to be described for optimizing the operation of different separation techniques with the ultimate objective of reducing operating expenses.

The vessel offers enhanced treatment through the utilization of microwave energy and mesh structure forming a Faraday cage enabling oil producer to increase throughput while avoiding costly capital expenditures.

The novel microwave dehydration design described in this paper was filed under US patent number 17/652,942 and titled "MICROWAVE ASSISTED OIL-WATER SEPARATOR".
Rethinking the Flow Management Strategy: Introducing Advanced Lower Completion as a Sustainable Technology in Brownfield Asset.
Authors: Martinez Santiago Maryvi , Ortiz Jhon , Bethapudi Bhanu , Mirza Gulraiz , Noordin Firdaus , Trisnadi Dicky , Mohammed Tawheed , Al Obeidi Mazna , Soufi Abdulrahman , Leal Cesar
Published: October 2022

Horizontal wells has been used across fractured reservoirs for field development, in presence of ununiformed water/gas saturation, introducing challenges for reservoir management. Premature water/gas production cause a higher bypassed oil, impacting its recovery and the business profitability.

Wells performance can be enhanced through advanced and sustainable technologies, conveying in the use of integrated lower completion (i.e. ICV, ICD/AICD, DHPG, PPL).

This paper discusses well/reservoir criteria, completion design and impact of incorporating these technologies in the Reservoir 1 development plan.

Early water/gas breakthrough, zonal isolation, cost, well productivity, complexity of deployment, and material availability have been part of the essentials to be considered in the process workflow from planning, execution and deployment phase. Dedicated Steady-state numerical solutions inflow parameters such as permeability and water-cut profiles modeling were carried out to provide the most suitable lower completion design. The simulation was performed for separate scenarios where Flow control devices (FCD) and Intelligent Completion IC were incrementally implemented. The outcomes were compared in terms of well cumulative oil and water/gas production thru the scenarios and their value quantified.

This opportunity screening and lower completion design (LCD) workflow have recently been applied at Reservoir 1 development plan. Based on the simulation cases outcomes, Six (6) new wells drilled in 2020-2022 are provided with FCD, IC, PPL expecting an incremental oil production and oil recovery with less gas and less water production consequently prolonging the well life. In Addition with the environmental benefits associated with less emissions that are achieved by reducing un-wanted fluids production.

There is a planned to be drilled three (3) more wells with LCD in the next five years as part of the new field development strategies that will improve the sweeping efficiency and oil recovery tackling the production of undesired fluids in a proactive manner.

Less associated emissions – The environmental benefits are achieved by reducing gas and water production, which supports company's commitments to emissions reduction target within their total production operations.
Deep-Set Velocity String for Liner Deliquification
Authors: Hajri Amira Salim , Ghaempanah Babak , Rashidi Ahmed , Veeken Cornelis , Awan Kamran
Published: October 2022

The installation of a smaller size tubing or velocity string inside an existing tubing completion is a well-known deliquification technique. The velocity string comes in various designs providing different functionalities for deliquification. Typically, velocity strings are installed to the top of the producing reservoir interval. In case multiple reservoirs produce across significant liner length (the liner here is the length/area between the two reservoirs), this "shallow" velocity string does not provide deliquification across the reservoir liner section. Depending on the size and length of the reservoir liner and the inflow performance of the producing reservoirs, the liquid loading across the liner can have significant adverse impact on production in which case deliquification by means of a "deep" velocity string installed across the reservoir liner becomes essential. This paper shares different designs, a modeling methodology and real-life assessment cases of such deep-set velocity strings, to achieve deliquification across the tubing completion above the reservoir and the liner completion straddling the reservoir. The proposed designs provide different flow options by changing the setting of sliding side doors (SSD's) embedded in the design or isolating the two zones by packers. The proposed modeling methodology helps to compare the performance of different flow options for shallow and deep velocity string designs. This paper continues by sharing three field cases of deep-set VS for the assessment of its real-life application.
Application of Autonomous Inflow Control Valve (AICV) in Reducing the Gas Production in Ultra-Light Oil Reservoir: Case Study
Authors: Kherroubi Djamal , Cristea Zaharia , Berrahmoun Hocine , Punnapala Sameer , Berdiyev Yunnus , Tveritnev Alexey , Saeed Alshehhi Shamma , Abd El-Fattah Mahmoud , Hooper Nicholas , Brough Brent
Published: October 2022

This paper describes the deployment of Autonomous Inflow Control Valve (AICV) technology in an oil producing well affected by gas breakthrough, to reduce gas production and increase conformance. Based on the fluid properties, AICV differentiates the fluid flowing through it and can autonomously choke / shut off gas inflow from the high gas saturated zones, while allowing oil production from healthy oil-saturated zones.

The subject oil producing well has open hole section of over 3200ft. A multidisciplinary data integration of well logs, production history, and subsurface geological description is considered for modelling and designing optimum AICV completion. The main objective is to restrict the gas breakthrough to a smaller compartment, allowing other compartments to produce at higher oil production.

The AICV completion was run with a remote actuated shoe to enable fluid circulation from the end of downhole completion string while run-in-hole. AICV technology allows pro-active reservoir management. It shuts-off the gas at subsurface level autonomously, without any intervention. Due to the chocking effect, AICV allows sustain the well production within the reservoir management guidelines, with improved well availability and reducing the operating expenditures. This has an additional positive impact on the environment due to reduction of gas flaring as AICV is expected to reduce the gas production/GOR by 81%

This paper discuss in detail how the AICV completion offered a technically attractive and cost-effective gas management and production optimization opportunity. Futures implementation of this solution will improve Miscible Water Alternating Gas (MWAG) injection efficiency and gas recycling in addition to reducing the carbon footprint per barrel of produced while sustaining production.
Data-Driven Characterization of Saturation Distribution for a Heterogeneous Carbonate Reservoir in Middle East
Authors: Wei Chenji , Huang Ruijie , Yang Jian , Gao Yan , Xiong Lihui
Published: October 2022

The middle east carbonate reservoirs are of tremendous potential, but due to the complex types of carbonate reservoirs and strong heterogeneity, the distribution characteristics of reservoir saturation are uneven, which makes reservoir development very difficult. The distribution characteristics of remaining oil are of great significance for evaluating development performance and preparing optimization plan. Deep learning offers a novel approach to solving this problem as a method of intelligent forecasting and analysis. In this paper, the dynamic reservoir production data were collected to establish the data foundation for data driven model training and forecasting. Then the Bi-GRU algorithm was utilized to forecast the performance of single well, which achieved high accuracy predictions with R2 of 0.91, RMSE of 198.93, and MAE of 85.22. After that, single-well temporal three-phase saturation inferring method was proposed based on dynamic performance data, relative permeability curves, and reservoir engineering methods. Finally, kriging interpolation algorithm was used to generate reservoir spatial three-phase saturation distribution. Compared with conventional numerical simulation methods, this method exhibits advantages in computational efficiency and prediction accuracy, and also provides a novel direction for saturation prediction research.
GPU-Based High-End Desktop Computing, A Cost-Effective Solution to Improve Reservoir Simulation Performance
Authors: Hernandez Quintero Maria de Los Angeles , Patacchini Leonardo , Al Remeithi Khaled , Figuera Luis Alfredo , Khait Mark
Published: October 2022

The ever-increasing resolution of reservoir simulation models, combined with the emergence of ensemble approaches, call for the adoption of simulators running on Graphics Processing Units (GPUs), as these offer unprecedented performance on limited hardware footprint. We here discuss how the adoption of such a tool within Mubadala Petroleum allows engineers to seamlessly run partners' models on local workstations, avoiding the complications of accessing cloud computing resources (no data transfer authorizations, challenging cost-control, risk of vendor lock-in, etc.).

Adopting new business-critical tools such reservoir simulators require careful validation; not only is the performance important, but also the stability and reliability. For instance, are the results sensitive to minor changes in the model? Or some others can lead to a change in hardware? In effect, in any nonoperating holding-company, it is furthermore important to be able to masterly reproduce the documented profiles. After a review of the principles of GPU based reservoir simulation, the process undergone to perform the above-mentioned validation were presented in this paper using local workstations.

Different simulation models with different levels of complexity have been tested using the GPU computing architecture of mid-end and high-end desktop computer (MEDC and HEDC). History matching and prediction runs were carefully validated against the original benchmark results. Additional tests and the performance scalability across various configurations were also explored. The comparison of different GPU-based computer gave the appropriate results compared to a highly invested option of having multiple multi-core processors, a cluster, or a networked computer.

The use of GPU-based high-end desktop computer (HEDC) will allow to deliver recommendations in time to support final investments decision, primarily because parallel solution simulations speed up simulation time, which is especially important in carrying out prediction solutions scenarios.

From this perspective, the added value of using GPU's HEDC presented in this study shows the significance and most convenient solution for decision making as a suitable option for Mubadala Petroleum.
Monitoring Health of Minagish Reservoir Through Tracking Movement of Reservoir Fluids
Authors: Kasaraneni Pruthvi Raj , Al Rashidi Tahani , Al Zamanan Mishary , Padhy Girija Shankar , Silambuchelvan Jeevan Kumar
Published: October 2022

This paper describes the methodology adopted to Monitor Health of Reservoir by tracking historical movement of reservoir fluids in an Oolitic limestone reservoir in Kuwait. The reservoir has a weak aquifer support, hence Gas injection followed by Water injection was implemented to provide necessary pressure support and improve overall reservoir sweep.

Since injection is being undertaken for a long period of time, drainage radius of water injectors is estimated through streamlines and accordingly the reservoir is divided into different regions based on the injection radius. Thereafter, historical movement of reservoir fluids in each region is analyzed for a period of 60 years to understand the following, Identify the position of leading edge of water and its associated flood-front with respect to each zone & region.Capture oil saturation changes during the last 60 years and identified which regions had minimal changes in oil saturation to accelerate implantation of new infill wells to maximize recovery.Locate where is the remaining oil in the reservoir and identified on what is it causing presence of remaining oil at any given location.Capture the changes in region-wise pressure by coupling with movement of Injected water.Generate distribution of Voidage replacement ratio and injection efficiency in different regions of the reservoir.
Production Profiling of a Long Dead Well – A Prime Case Study of Operational and Technical Excellence Using Simultaneous Lifting and Logging Services
Authors: Akram Shahbaz , Yousaf Haleem , Nawaz Omar , Ashraf Zaid , Zubair Talha , Tanveer Muhammad Sohaib , Bari Abdul , Ali Hamza , Farooq Muhammad Omer , Molero Nestor , Khan Rao Shafin Ali , Naveed Muhammad Amir
Published: October 2022

Reservoir surveillance and production optimization will remain at the forefront of company strategies in the new post-COVID19 environment. We anticipate that companies will focus more on producing assets and go the route of production enhancement rather than exploration. Accordingly, production logging will remain an important surveillance method in evaluating and strategizing production-optimization schemes pertaining to flow-characterization from reservoir-to-wellbore. This work is culmination of operational and technical excellence that enabled the revival of a loaded-up well through simultaneous lifting-and-logging technique.

Conventionally, wireline is the preferred mode of conveyance for production-logging; however, well must be continuously flowing throughout acquisition timeframe. Kicking-off the well using nitrogen-lift and then bringing in wireline-unit for production-logging in Well A-4 was not feasible as previous attempts confirmed well to load-up in few hours post-offloading. Therefore, success of this project was heavily dependent on initial planning stage, which accounted for all available data including production-history, well-events, intervention-details, fluid analysis and well load-up behavior. Next, a multi-domain approach was adopted while bringing-out each domain from its silos and strategize collectively to simultaneously kickoff the well with nitrogen and acquire real-time downhole production-logging data through smart-coiled-tubing (CT). This was first implementation of concurrent lifting and logging operation in Pakistan.

By deploying the approach mentioned above through smart CT (using optical-telemetry-link inside the CT-string coupled with downhole-assembly), synchronized lifting-and-logging operation was carried-out successfully. Well was observed to swiftly go back to load-up conditions post-kickoff; however, continuous well dynamics monitoring downhole enabled us to log perforated interval across multiple time domains. Well was activated through CT nitrogen-injection but depicted continuous loading tendency, which was captured downhole in form of flow-transients. Real-time job optimization ensured vigilant monitoring and selection of right-time to acquire meaningful zonal-contribution data for evaluation and diagnostic solutions. Finally, operational excellence was complemented through technical data analysis and interpretation, integrating passes data with transients and stationary measurements. Ultimately, acquired data analyzed using an integrated lens involving fluid velocities, downhole density, temperature, and water hold up data. Consequently, enabling us to decipher gas and water-entries on a zonal-basis across perforated sandstone reservoir.
An Integrated Solution for Reservoir Model Initialization with Areal and Vertical Composition Variation in the Presence of Tilted Contacts
Authors: Ghorayeb Kassem , Tahir Sofiane , Su Shi , El-Droubi Nour , Assaf Georges , Ramatullayev Samat , Kada Kloucha Chakib , Mustapha Hussein
Published: October 2022

Capturing fluid composition variation and distribution in the reservoir is an essential first step for reservoir modeling. Vertical fluid composition variation is commonly considered. However, fluid samples taken from wells in different areas of a reservoir can highlight significant areal variation in the composition to be modeled. Fluid contacts may be tilted, and despite many studies on the subject, the setup is not straightforward. The combination of all three makes the initialization challenging and time consuming.

In this paper we describe an automated workflow that integrates fluid sample data and petrophysical data to generate an initial fluid composition distribution that captures vertical and areal composition variations and accurately computes the initial fluid distribution to represent tilted contact configurations and their associated transition zones.

Fluid sample data such as composition, pressure, temperature, and sampling depth are provided to an engine that computes composition variation with depth for each sample based on the equation of state (EOS) that characterizes the fluid behavior of the reservoir. The generated composition variation with depth for each sample is spatially distributed at their associated wells and is used to compute the areal composition distribution between the wells in the reservoir. This results in a tridimensional distribution of each fluid component representing the fluid model that captures both vertical and areal composition variations.

In parallel, saturation height functions and hysteresis models are used to automatically generate drainage capillary pressure data and associated imbibition and scanning curves used to capture the drainage and imbibition processes responsible for the paleo and current water saturation distribution in the reservoir.

The fully automated reservoir initialization process accounts for all available pressure-volume-temperature (PVT) samples. The solution is portable, significantly faster, and accurately captures complex reservoir geology and reservoir history. We present field examples of the proposed approach and illustrate its flexibility and associated comprehensiveness and efficiency.

The complete automation of complex initialization methods considering areal and vertical composition variation, combined with tilted contacts modeling, is helping to resolve significant challenges faced across the industry.
Commingled Well Test Analysis (CWTA) and its Application to Assess Health of Multiphase Flow Meters (MPFM) for Deep Water Conventional Assets
Authors: Patra Susobhan , Kedia Kushal , Gollu Divakar , Gantt Justin , Long Ted
Published: October 2022

Historically well production flow surveillance has been attracting attention from reservoir engineers. The accurate estimation of individual well contribution, Has profound impact on reservoir management. Often production allocation suffers from multiple issues such as quality of available production data and production rate estimation in case of inaccurate and uneconomical measurements. These issues can be mitigated if the well has accurate, calibrated Multiphase Flow Meters (MPFMs) and Virtual Flow Meters (VFMs). Reliability of digital meters is primarily dependent on regular well testing to keep the model updated and tuned to latest reservoir characteristics.

As an industry wide common practice, well tests are performed in a timely manner to ensure to allocate production accurately to each well. But performing solo well tests for subsea wells is not trivial as it may seem. Differed production due to downtime associated with flowing subsea wells to a test separator and inability of mature wells to flow to the test separator result in additional challenges. Under such situations, commingled well tests are performed to estimate well rates. Individual well rates can be estimated using test by difference (TBD) method. The apparent simplicity of the TBD method often results in incorrect estimation of allocation rates as the test conditions and production conditions differs significantly. As a result, the credibility of the forecast and the ability to optimize production are compromised.

In this paper a novel application called Commingled Well Test Analysis (CWTA) is reviewed which addresses these aforementioned issues. This integrated application comprises of data loading interface, data visualization interface, core optimization engine and an interactive user interface. To demonstrate the capability, three wells from a deep water conventional wells are analyzed using commingled well tests and well performance parameters (PI, WCUT and GOR) are obtained. Based on the tuned parameters, well rates are predicted and compared against rates obtained from sales meter and MPFM meters. As per the comparison, well allocation rates are validated and health of MPFM meters are assessed. As an additional benefit, proper designing of commingled well tests enable in 25-30% time savings of well testing.