bluuebunny/crossref_metadata_2025_split huggingface dataset:
Designing an Optimum Recipe for SP Flooding in Harsh Carbonate Reservoir Conditions High Temperature High Salinity
Authors: Ahmed M. Elmuzafar , Sultan Abdullah , AlSofi Abdulkareem , Al-Hashim Hasan 
Published: March 2022

Abstract
Chemical-Enhanced-Oil-Recovery (CEOR) processes have been used for increasing oil recoveries from oil reservoirs following the primary recovery phase. At harsh reservoir conditions (high salinity and high temperature), many CEOR methods fail to achieve their objectives. This raises the challenge to design optimum recipes that tolerate these harsh conditions and hence attain maximum hydrocarbon recovery at the minimum possible cost.
This paper evaluates the effectiveness of a Thermo-Viscosifying Polymer (TVP) and an Acrylamido Tertiary Butyl Sulfonate (ATBS)/acrylamide (AM) copolymer in mobilizing residual oil from carbonate. The surfactants are carboxybetaine based amphoteric surfactants SS-880 and SS-885. These candidates were selected based on an intensive evaluation process carried out in previous works at KFUPM, which includes fluid rheology, long-term thermal stability, interfacial tension (IFT), adsorption and microfluidic studies. Furthermore, contact angles were measured at high pressure and high temperature using a captive drop analyzer. Slug size and injection sequence optimization were also investigated through core-flooding experiments. Different injection scenarios including SW-SP-SW, SW-P-S-SW, SW-S-SW-P-SW and SW-P-SW-S-SW were also investigated to identify the best injection scenario. The coreflooding experiments were conducted at 90°C. The seawater (SW) used in this study is Arabian Gulf seawater having salinity of 57,000 ppm.
The results showed that surfactant-polymer combination and SW-SP-SW injection scenario were the best in terms of oil recovery. The optimum chemical combination was found to be carboxybetaine (0.05% wt.) and ATBS/AM (0.25% wt.). It was also observed that the recoveries were increasing proportionally to the slug-size. This indicates that the chemical injection sequence and slug-size have a significant impact on ultimate oil recovery. This is believed to be due to the advantageous synergies between the chemicals. The core-flooding experiments confirmed the importance of optimizing the design of CEOR processes taking into consideration the type of chemicals, concentrations, slug sizes, and flooding sequence of the different combination of seawater (SW), surfactant (5) and polymer (P).
Innovative Tailored Spacer System Helps Mitigate Losses and Enhance Cement Bond Log in a High-Lost Circulation Zone on the Largest UAE Offshore Field
Authors: Hamidzada Ahmedagha , Elhassan Azza , De Barros Adelson Jose , Alaleeli Ahmed Rashed , Torres Javier , Medina Ruben , Baouia Bilal , Agapiou Kyriacos 
Published: March 2022

Abstract
Lost circulation (LC) is commonly encountered in drilling and cementing operations and can be a costly problem that increases nonproductive time (NPT). Various methods can be applied to control losses—from applying best operational practices to incorporating LC control materials in treatment fluids and cement slurries. Among the cementing challenges, the loss of circulation can also be associated with poor zonal isolation and becomes more critical when zones between reservoirs should be covered to avoid sustained casing pressure (SCP) in the future and to extend the life of the well.
The application for this tailored spacer was the first one globally. Challenges addressed in the largest offshore field loss zone in the UAE included a high likelihood for losses during initial cementing, narrow equivalent circulating density (ECD) gradient, uncertainty in bringing cement to surface in the casing operation, and zonal isolation between reservoirs, formation, and caprock. As part of the best cementing practices, the design and tailoring of the spacers should be considered. Correct use allows the cement to cover zones of interest with less contamination, and cement properties can develop and interact efficiently with the formation.
Using a tailored spacer fluid system engineered to effectively and efficiently help prevent LC and maintain wellbore stability while preparing the wellbore to receive cement is discussed. The tailored spacer system uses additive synergies to help prevent LC in porous and fractured formations and enables control of rheological hierarchy and wellbore fluid displacement efficiency. The spacer was designed to optimize cementing operations where losses are observed and, in this case, incorporate additional LC materials to help prevent severe losses and achieve the desired top of cement (TOC). The tailored spacer system was pumped ahead of the cement slurry, to reduce permeability across the formation, with superior properties that help prevent fluid loss of the cement to the permeable formations.
Enhancing the cement bond and allowing an effective mud removal differentiate it from a conventional spacer. Using this spacer system enabled cementing goals to be achieved. Cement was brought to the surface, casedhole logs exhibited excellent cement bonding, and no SCP was registered, helping eliminate the need for unwanted remedial operations to secure the zonal isolation, which saves rig time.
Dynamic Data Integration in Dual-Porosity Dual-Permeability Reservoirs: Permeability Conditioning Perspective
Authors: Alramadhan Aymen , Lyngra Stig 
Published: March 2022

Abstract
Advancements in pore-scale and core-scale studies have provided an improved understanding of the micro- and macro-porosity nature of carbonate rocks and how the two systems interact. The interaction of the two systems in the presence of a third (fracture) and fourth component (vugs) has not been fully investigated in the industry. This paper demonstrates applicability and some limitations of permeability conditioning practices in dual-porosity dual-permeability (DPDP) systems. In addition, this work demonstrates how the permeability conditioning process can be used as a tool for dynamic classification and calibration of extreme permeability (super-k) intervals in dual-permeability systems.
A highly scalable parallel DPDP finite difference simulator is used to: Firstly, demonstrate the permeability conditioning process and how it impacts reservoir dynamics. Secondly, present cases where flowmeter (PLT) responses show a limitation in characterizing super-k intervals and its impact. Thirdly, demonstrate the role of enhancement factor in representing flood front movement for multiple super-k dominated reservoir realizations constrained by flowmeter and pressure transient permeability-thickness controls.
The results of this work expands on the representation of super-k intervals in dual-permeability systems in three main areas. Firstly, the decision to explicitly model super-k intervals as a fractured media or to implicitly model these features as a matrix permeability enhancement should be evaluated with use of enhancement factor combined with water breakthrough trends observed in the field. Secondly, the use of PLT responses to characterize super-k intervals should be made after careful evaluation of their responses before and after any well intervention. This step is crucial for proper permeability conditioning and in capturing reservoir dynamics of masked high flow intervals, i.e., new flow dominating features that appear only after the original super-k intervals have been plugged. Thirdly, as part of the integration of pressure transient results into a DPDP finite difference model, special consideration is needed for wells with a non-intersecting conductive fracture signature due to a limitation in the Peaceman formulation for DPDP reservoirs, which only considers cells intersecting the well for productivity index and PLT response calculations.
In summary, this paper provides guidance for geologists and reservoir engineers, through use of a permeability conditioning process, to dynamically classify and calibrate fractured/super-k intervals during the process of constructing full-field dual-porosity dual-permeability reservoir simulation models.
The Role of Dispersion in Enhanced Gas Recovery and Gas Field Pressure Maintenance
Authors: Van Dorp Johan J. 
Published: March 2022

Abstract

Objectives
Enhanced Gas Recovery (EGR) is the process whereby an inert gas like nitrogen or flue gas is injected in a gas reservoir to improve hydrocarbon gas recovery. One of the objectives of EGR is recovery of remaining gas in place at the prevailing abandonment pressure by sweeping native hydrocarbon gas with an inert gas.
This paper treats the reservoir engineering aspects of dispersion in gas displacement by nitrogen.

Methods
Relevant theory and knowledge from literature are applied to an example sandstone gas reservoir.

Results
The displacement is typically miscible, and the higher viscosity and density of the injected nitrogen over the native hydrocarbon gas improves the stability of the vertical displacement front. However, dispersion in the reservoir is another potential source of spreading of the front. This leads to early nitrogen breakthrough and a slowly growing nitrogen concentration in the production stream that needs to be dealt with prior to sales through N2 removal or dilution of the produced gas with other gas streams. Reservoirs with low formation dispersivity are therefore the most suitable targets for EGR. This leads to the selection of homogeneous reservoirs with short correlation distances of depositional features. Formation dispersivity is ideally measured upfront using a tracer push-pull test. As a result of the physics of the dispersion process a line drive with a large displacement well spacing provides an optimum selection as (horizontal or vertical) well configuration. Selection of high viscosity injection gas helps to increase the stability of the displacement front.

Novelty
Stabilization of the injection front by foam would significantly enlarge the targeted group of fields for EGR to include reservoirs with more adverse heterogeneity. R&D is required to establish a likely reduction in dispersion.
Accurate modelling of the mixing process is possible by tagging the injection fluid with a passive tracer while solving the advection equations explicitly using a higher order scheme to reduce numerical dispersion. Only physical dispersion at the sub-grid scale should be included. This modelling method could however lead to unstable displacement in the simulator because the density and viscosity contrasts are ignored.
Dual Heuristic Dynamic Programming in the Oil and Gas Industry for Trajectory Tracking Control
Authors: Al-Dabooni Seaar , Tawiq Alaa Azeez , Alshehab Hussen 
Published: March 2022

Abstract
This paper presents the state-of-the-art of the artificial intelligence algorithm, named dual heuristic dynamic programming (DHP) that uses to solve the petroleum optimization-control problems. Fast self-learning control based on DHP is illustrated for trajectory tracking levels on a quadruple tank system (QTS), which consists of four tanks and two electrical-pumps with two pressure control valves. Two artificial neural networks are constructed the DHP approach, which are the critic network (the provider of a critique/evaluated signals) and the actor-network or controller (the provider of control signals). DHP controller is learnt without human intervention via repeating the interaction between an equipment and environment/process. In other words, the equipment receives the system states of the process via sensors, and the algorithm maximizes the reward by selecting the correct optimal action (control signal) to feed the equipment. The simulation results are shown for applying DHP with QTS as a benchmark test problem by using MATLAB. QTS is taken in the paper because QTS is widely used in the most petroleum exploration/production fields as entire system or parts. The second reason for using QTS as a test problem is QTS has a difficult model to control, which has a limited zone of operating parameters to be stable. Multi-input-multi-output (MIMO) model of QTS is a similar model with most MIMO devises in the oil and gas field. The overall learning control system performance is tested and compared with a heuristic dynamic programming (HDP) and a well-known industrial controller, which is a proportional integral derivative (PID) by using MATLAB programming. The simulation results of DHP provide enhanced performance compared with the PID approach with 98.9002 % improvement. Furthermore, DHP is faster than HDP, whereas DHP needs 6 iterations, while HDP requires 652 iterations to stabilize the system at minimum error. Because of most equipment in the oil and gas industry has programmable logic control (PLC), the neural network block has already existed in the toolbox of the PLC program. Therefore, this project can apply in real by installing PLC to any equipment with DHP toolbox that connects to the sensors and actuators. At the first time, the DHP toolbox in PLC is learnt by itself to build a suitable robust controller. Then, the DHP controller is used during normal situations, while if any hard events happen to the equipment (the PID controller cannot handle it), the DHP toolbox starts learning from scratch again to overcome the new situations.
Non-Isothermal Compositional Simulation Study for Determining an Optimum EOR Strategy for a Middle-East Offshore Heavy-Oil Reservoir with Compositional Variations with Depth
Authors: Salimi Hamidreza , Sieders Bram , Rostami Javad 
Published: March 2022

Abstract
The objective of this study was to find an optimum EOR strategy for a Middle-East offshore heavy-oil reservoir that exhibits reservoir-fluids-properties variations with depth using non-isothermal compositional simulations that honor the fluids-compositional variations with depth. The observed compositional variations are such that the oil density changes from 20 °API in the crest to 11 °API in the deep part and the live-oil viscosity increases from 14 cP in the crest part to 449 cP in the deep part of the reservoir. Because the concept of thermodynamic equilibrium is not valid for the reservoir with compositional variations, we used the theory of irreversible thermodynamics to develop a compositional PVT model that captures the observed compositional and oil-properties variations with depth. Next, the PVT model was tuned against CO2 and hydrocarbon-gas swelling and MMP tests. Subsequently, we developed a compositional reservoir dynamic model that uses the single compositional PVT model and can simulate the degree of CO2/hydrocarbon-gas miscibility in oil. Then, we performed a dynamic IOR/EOR screening that includes water injection, hydrocarbon-gas injection, CO2 injection, water-alternating-CO2 injection, polymer injection, polymer-alternating-CO2 injection (PAG-CO2), and simultaneous polymer and CO2 injection (SPCO2). For simultaneous polymer and CO2 injection, polymer was injected at the top while CO2 was injected at the bottom. The simulation runs of these scenarios were elucidated in detail.
The developed compositional PVT model successfully reproduces the observed fluids-properties and compositional variations with depth. In this way, the calculated fluids properties are continuous with depth because there is only a single PVT model for a single PVT region. The performances of different EOR scenarios were compared with each other. The simulated incremental oil recovery increases in the sequence of water injection, hydrocarbon-gas injection, WAG-CO2 injection, CO2 injection, polymer (22 cP) injection, PAG-CO2, and SPCO2. The reason for higher incremental recoveries with combined CO2-polymer scenarios is that both the macroscopic sweep (with polymer) and microscopic displacement efficiency (with CO2 and polymer) remain high. Although the CO2 injection pressure is lower than the MMP, the condensing- and vaporizing-gas drives are very efficient to the remaining oil saturation to low values (&lt; 0.10). The other advantage of SPCO2 injection is that the intermediate and deep layers are well contacted and swept by the injected fluids. At the crest scale, combined CO2-polymer scenarios can increase the do-nothing recovery by 85–119%.
Production Technology Selection for an EOR Redevelopment Project – Lessons Learned from Polymer Pilots
Authors: Hoy Michaela , Cimitoglu Timur , Knauhs Philipp , Steineder Dominik , Sieberer Martin , Kornberger Martin , Molstre Oystein 
Published: March 2022

Abstract
OMV Austria E&P GmbH operates 26 oil fields in Lower Austria. The majority was developed in the 1950s and 1960s and shows an extended decline period. The challenge of operating brown fields is seen to maintain a reasonable oil production over time in a cost effective manner - this can be tackled by a major chemical enhanced oil recovery field redevelopment project. The scope of the polymer field rollout is to create and efficiently operate horizontal polymer injection patterns in two horizons in Lower Austria.
OMV follows the strategy to pilot new reservoir and production technologies before their application in field rollouts. Due to the large project investment volume it is crucial to derive information and lessons learned from existing pilot patterns to optimize conceptual decisions on artificial lift, completion, sand control and injection strategy and to reduce technical risk.
In the past 10 years several vertical pilot patterns were created to analyze the efficacy of polymer injection in the Tortonian Horizon. Significant operational experience in water treatment, polymer injection and polymer back production, but also in tracer testing was established.
Since already the vertical polymer patterns showed not only operational success, but also significant incremental oil production, the idea of horizontal flooding patterns was born. To confirm and understand the impact of polymer injection also in horizontal wells, a first horizontal pilot pattern was drilled; additional pilot wells are currently following. For a future field redevelopment the technology selection should be de facto based on either standard or pilot-proven technologies.
This paper describes measures undertaken in the discipline of production technology to prepare for one of the largest field redevelopment projects in the history of OMV Austria. These measures include the application of several pilot projects in the field of artificial lift, completion design and sand control, production and injection allocation. Therewith production technology serves the needs for active reservoir management and thus, follows a holistic field development approach.
Agility in BP Oman – Doing More with Less
Authors: Al Farsi Ghaida , Jayawickramarajah Angeni 
Published: March 2022

Abstract
In this age, there are many technology companies that specialize in big data analytics, making every piece of data useful to the end user. At BP, we have strived to build and utilize tools that enable us to work meaningfully with our data – to proactively eliminate defects across reservoir and well chokes, to track our well vulnerabilities, and flag well performance issues easily – so we can transform this data into value-adding actions.
A suite of tools had to be built to meet our objectives. The first tool, called the Production Management Tool (PMT), utilizes automation and machine learning capability to estimate live reservoir pressure and productivity index in real-time, generate short-term production profiles for every well using a decline curve analysis concept, flag opportunity and risk using a wells heat map, and optimize well decline using one platform. The approach to estimate live reservoir pressure in a tight gas field, without utilizing a reservoir model, is unprecedented. It allows for a live estimation, without any waiting time which is the case with traditional methods. Similarly, decline curve analysis on a high gas capacity wells which are choked back is difficult and questionable, as there is no decline detected. Through PMT, a decline curve analysis concept is possible by modelling declines on a well's capacity rather than its actual rate. These innovative approaches rely on industry known methods that have been repurposed and transformed to incorporate the latest data science concepts.
Next, a Hidden Defects Tool was constructed, which proactively drives defect elimination across the reservoir and well chokes by quantifying unproduced gas rate and condensate deferrals and assigning those deferrals to defect categories. This tool also supports the user in initiating remediation plans by describing the production risk in an interactive visual dashboard. Finally, a vulnerability matrix was constructed to link our hidden defects conclusion and well performance metrics to understand the biggest production threats by visualizing the risk severity based on well groupings, or overall risk value.
All these tools highlight the importance of remaining current with the latest technology, as it can provide huge potential to advance technical capabilities and maximize business value.
Managing the High Water Cut Behavior in a De-Saturated Reservoir and Maximize the Oil Gain
Authors: AbdelSamiee Rady , Sariri Abdul Aziz , Hatmi Safiya , Hinai Mohammed , Hamm Carmen , Singh Jasbindra , Hinai Saif , Hamhami Saif , Azri Nasser , Al Asmi Hatim , Farsi Yahya , Abazeed Osama 
Published: March 2022

Abstract
A new technology utilizing the Autonomous Inflow Control Device (AICD) has been used in horizontal wells producing from a viscous oil reservoir to restrict the unwanted water breakthrough and maximize the oil gain. The added benefit of greater reservoir contact has met with increased differential drawdown across the horizontal section to manage the reservoir heterogeneity.
AICD is an active flow resistance element distributed along the length of the horizontal well-bore section to delay and reduce the proportions of the water breakthrough. The AICDs impose a relatively strong resistance for low-viscous fluids over the high viscous oil. This is due to the changes in the flow area internally in the AICD. With this technology, oil production can be increased while restricting the water inflow into the wellbore. The AICD operates without the need for human or surface interventions and electric or hydraulic power.
AICD technology has been piloted in two new wells in two fields located in South Oman. The reservoir contains viscous oil (400-600 cp) and exhibits high inflow potential due to favourable rock properties and strong bottom water aquifer. Horizontal wells have been used to maximize reservoir oil contact and improve recovery from the reservoir. The wells, in general, produce oil with very high water cut (&gt;95%). Two horizontal wells were drilled recently, and each well was completed with AICDs along a completed lateral length of 500 m. The AICDs managed in bringing down the water cut to less than 5% from 95% observed in the surrounding wells. The production behaviour has been sustained for nearly a year now.
The success of the AICD trial has opened the doors for its wider use in reservoirs containing viscous oil. The AICD also has been tried in existing wells where it managed to reduce the gross and the water cut by 50% and increase the oil gain by 100%.
Plans are also in place to extend the AICD trials in existing wells and reap the benefits by maximising oil production while decreasing the unwanted water production.