bluuebunny/crossref_metadata_2025_split huggingface dataset:
Anti-Foam Injection Optimization
Authors: Derebe Addisu Tadesse , Al Neyadi Salem , Nasser Fadhal Mohsen , Al Nuaimi Ibrahim , Damanik Brama , Romi Ahmed Ibrahim 
Published: October 2022

Abstract
Habshan-5 & Sulphur Plant consists of two Rich Acid Gas Removal Units (AGRU) designed to process a total of 1340 MMSCFD of sour feed gas. These units utilize MDEA solution to produce close to H2S-free sweet gas. The objective of this study is to minimize the continuous dosing of anti-foam in the AGRUs without increasing the foaming tendencies, while maintaining sweet gas specifications. Consequently, leading to a significant reduction in the operating cost.
The method used was the reduction in anti-foam continuous dosing rate in a gradual manner. Each phase lasted for approximately one month, which gave enough time to stabilize the unit and collect sufficient reliable data. Meanwhile, several parameters were monitored on regular basis, such as foam height, foam breakdown time, absorber pressure drop and sweet gas quality. Parameters were gathered using laboratory analysis and PI ProcessBook software. These parameters were then compared against design values and trends analyzed before making decision to go ahead with the next phase or revert to earlier dosing rate.
In phase 1, anti-foam dosing rate was reduced from 90 L/hr. to 50 L/hr. Foam height remained below target of 20 cm and even showed slight reduction compared to before. All other parameters were within acceptable limits, and no noticeable changes compared to earlier data.
Anti-foam dosing rate in phase 2 was reduced from 50 L/hr. to 40 L/hr. The overall foam breakdown time for both units had a small drop, which indicated a slightly reduced foaming tendency. There were no changes in the other parameters.
The anti-foam dosing rate in phase 3 was reduced again from 40 L/hr. to 30 L/hr. All parameters were within the acceptable limits, and there were no changes compared to phase 2.
In phase 4, anti-foam dosing rate was reduced from 30 L/hr. to 20 L/hr. Foam height and breakdown time increased significantly to 100 cm and 100 seconds respectively. It was determined that maintaining dosing rate at 20 L/hr. would eventually lead to a foaming event. Thus, dosing rate was increased back to 30L/hr. permanently and trial was completed.
Overall anti-foam consumption was reduced by 53%. This initiative shows how decrease in operating costs can be achieved by optimizing chemical injection rate without jeopardizing the safety and integrity of the plant.
Evaluation of Flow Diverter Chemical to Improve Waterflood Performance as Conformance Control for Heterogeneous Reservoir and High-Temperature Field Application: An Innovative Experimental Design
Authors: Zulkifli Nazliah Nazma , Hendraningrat Luky , Razali Norzafirah , Bakri Che Nasser , Zainal Suzalina , Kechut Nor Idah 
Published: October 2022

Abstract
Water injection fields account for over half of Malaysia's oil production, with most of these fields at matured waterflooding stage. Low sweep efficiency due to water conformance where reservoir with high heterogeneity might cause premature breakthrough is one of the issues that leads to low oil recovery. In this study, we described the comprehensive experimental analysis to substantiate waterflooding performance in heterogeneous reservoirs by evaluating the flow diversion chemical (FDC) as a water conformance agent at high temperature. Chemical characterization, rheology, particle size analysis, compatibility, and thermal stability were evaluated for FDC according to the prevailing mechanism. Afterward, an experiment to simulate the reservoir environment was conducted to estimate oil incremental and blocking mechanism, in terms of residual resistance factor (RRF) performance in the intended field condition. The test was innovatively set up using commercial outcrop and reservoir native cores in dual-core permeability systems to test high permeability and low permeability porous media at high temperature up to 115°C temperature to mimic the conformance process. Typical single core flooding test are only able to determine the potential of the blockage mechanism by determining the RRF, without the diversion effect to quantify the additional oil recovery from the flow diversion process. The setup uses cylindrical preserved core plug samples with permeability contrast ranges from 100mD to 2 Darcy and tested at 115°C. The customized coreflood design successfully mimicked the conformance process. In our study, the RRF of 186 and cumulative oil recovery of 52% with an incremental oil recovery of &gt;5% was obtained by the FDC injection. The study provides an innovative way in the coreflooding experiment to evaluate the performance of a conformance control agent in a heterogeneous reservoir with high temperatures.
Application of Linear Programing in Optimisation of Gas Blending Operations
Authors: Zhainakov Timur , Chong Yin Chao 
Published: October 2022

Abstract
Different fields and wells produce natural gas of different composition, which directly influences the value of the gas. This gas is then sent to customers depending on the individual specification. Gases from different origins are sometimes blended to make up for the minimum rate requirement. This study presents a mathematical approach, linear programming, to process big data and generate an optimized route that solves a rate allocation problem keeping in place various operational constraints.
A base model was created based on linear programming algorithm for the proof of concept. As in industry, multiple sets of constraints were applied to the model. These constraints include, for instance, maximum allowable carbon dioxide concentration of the total blend, minimum amount of gas, or target ethane concentration for various purposes. Another feature that was included in the model was Blend Specification Requirements. This feature navigates the solver to which result is more favourable and would provide higher profit. The final goal of the solver is to provide a scenario that complies with all the constraints providing the best revenue.
The results of the multiple test optimizations, generally, showed close agreement with predictions made prior the tests. Once the model was validated, more complex scenarios were evaluated. Here, the model-generated results showed completely different from the expected. This error in predictions is due to the nature of the problem i.e., rate allocation planning, where the number of considered variables directly influences the complexity of the decision, making it impossible for basic experience-based predictions. The soft-constraint Blend Specification Requirement principles proved to function and direct the solver towards the higher profitable arrangements, while complying to the hard-constraints. Soft and hard terms here relate to the level of the obligement that must be performed by the solver. Overall, the model succeeded in optimizing the relationship between the economic values of different natural gas compositions and the operational and blend constraints, identifying the most profitable gas distribution plan.
It is no longer practical to rely solely on the experience of individuals when dealing with complex rate allocation operations. This study presents a simple, reliable and elegant method to build computer-based optimisation models. Connected to an online stream of Big Data, the models can potentially contribute to oil and gas pipeline rate allocation operations, making decisions fit-for-purpose, cost effective and reliable.
Dynamic Mitigation Strategy to Flow Assurance Challenges Associated with CO2 EOR in an Onshore Abu Dhabi Field
Authors: Abdallah Dalia , Grutters Mark , Igogo Arit , Singh Manjit Kumar 
Published: October 2022

Abstract
A CO2-WAG (water-alternate-gas) injection EOR pilot is currently ongoing in a carbonate reservoir, in an Onshore Abu Dhabi field, as part of the company's strategy for Carbon Capture, Utilization and Storage. The pilot is an important phase to de-risk challenges associated with CO2 injection prior to full field implementation. This paper will focus on the mitigation of subsurface flow assurance challenges to handle corrosion, asphaltene and inorganic scaling risks in production wells.
As the conditions change during the CO2 pilot duration from producing dry oil to producing oil with miscible gas along with water, the flow assurance mitigation strategy must change to address the different challenges at each stage. Based on extensive lab studies and modeling work confirming the risk of corrosion, asphaltene and scale, it was decided to equip producer wells with downhole chemical injection facilities. Inhibitors for different applications were lab qualified as part of the chemical program to be injected, upon demand, during the pilot life cycle.
A comprehensive surveillance program of gauge cutter runs, logging and fluid sampling was put in place to monitor pilot performance and changes in fluid properties and conditions that warrant mitigation by chemicals. The plan was to inject corrosion inhibitor at the start of the pilot and switch to a corrosion/asphaltene combo chemical with CO2 break-through, as it tends to destabilize asphaltene and lead to deposition. Once water cut increases, asphaltene deposition starts to diminish and the risk of inorganic scale increases. At that stage the strategy is to switch back to corrosion inhibitor injection with scale inhibitor squeeze application into the reservoir to protect from scaling.
The pilot has been operational for 5 years. Water cut increased in producers from 0% to &gt; 10% with instances of inorganic scale deposition in the lower part of the tubing. This was handled through acid washes due to favorable economics in comparison to inhibitor injection. CO2 levels at the producers increased from 6 mol% to 13-20 mol%, confirming CO2 break-through. With an effective corrosion inhibitor injection, the time-lapse corrosion logs confirmed that the tubing was in good condition. No asphaltene deposition experienced up to date hence no asphaltene inhibitor injection was administered.
This paper describes steps required to assess different flow assurance challenges during a CO2-WAG pilot and outlines the mitigation strategy including a robust surveillance program during pilot execution. This mitigation strategy should be dynamic, responding to the changes in challenges posed at each phase considering the most cost-effective solution. For scale and asphaltene deposition the frequency of occurrence should be considered to decide on whether to inject inhibitors or apply solvent soaks.
Which is the Most Attractive IOR Method to Produce the Venezuelan Highly Viscous Oil Resources in the Energy Transition Era? A Comprehensive Review of Research and Field Applications
Authors: Rodriguez Fernancelys , Delamaide Eric , Rousseau David , Bekri Samir 
Published: October 2022

Abstract
Venezuela has been a potential producer of highly viscous crude oils for more than a century, thanks to its large resources located at the Lake Maracaibo and Eastern Venezuela basins in the Orinoco Oil Belt. Despite these huge resources, Venezuelan oil production is going through one of the greatest crises in its history, presenting a dramatic production decline, for which the application of Improved Oil Recovery (IOR) methods with low environmental impact (low carbon emissions, low water consumption, etc.) is crucial to increase oil production.
The main methods applied in Venezuelan highly viscous oil reservoirs (heavy, extra-heavy and bituminous oil reservoirs) have been cold production with sand by vertical and horizontal wells with artificial lift pumps, waterflooding, thermal IOR/EOR methods (steam drive-based methods), chemical EOR (CEOR) methods, namely polymer and surfactant-polymer (SP) flooding, hybrid methods (e.g. thermal combined with solvents or CEOR methods), among others.
Research works in CEOR methods for Venezuelan highly viscous oil reservoirs have shown that high oil recoveries may be possible for oils with viscosities up to 13,400 mPa.s. On the other hand, for the case of bituminous oil reservoirs (e.g. viscosities up to 50,000 mPa.s) thermal IOR methods and combinations with chemicals, nanoparticles, or solvents may increase oil production significantly. The methods reviewed in this article are: waterflooding, chemical flooding (e.g. polymer, surfactant, alkali and a combination of them), steam drive methods (e.g. CSS, In-situ Combustion and SAGD), solvent flooding, microorganisms and hybrid methods.
Based on research and field tests, CEOR methods may lead to increased oil recovery of extra-heavy oils with low carbon emissions compared to thermal EOR methods, thus making SP flooding and low salinity polymer flooding among the most attractive technologies. Depending on the type of chemicals evaluated, recovery mechanisms such as mobility control, IFT reduction, ion exchanges and/or wettability alteration might be most efficient. It also appears that hybrid methods have achieved the highest recovery at the laboratory scale (e.g. In Situ Combustion with nanoparticles). For the medium-heavy oil reservoirs of the Maracaibo Lake Basin, waterflooding combined with infill well optimization and microorganism flooding are encouraging IOR methods with low environmental impact. The greatest challenges in the application of these technologies are related to technical and economic considerations that will be decisive for the implementation of the IOR processes at the pilot scale and/or massification at the field scale aiming to increase Venezuelan oil production in this era of the energy transition.
Reservoir Performance Analysis of Eighty-Four Years of Immiscible Gas Injection in a Matured Carbonate Reservoir, Bahrain Field
Authors: Hameed Mohamed , Konwar Lakshi , Alanaisi Isa , Ali Waleed , Alawainati Ebrahim 
Published: October 2022

Abstract
The Bahrain Oil Field ("Bahrain Field"), wherein the first oil discovery was made in the Gulf region in 1932, is now in a mature stage of development. Mauddud is the major oil-producing reservoir in the Bahrain Field, situated in an anticlinal feature of the middle cretaceous period. This is a highly undersaturated, low-dip, layered, heavily faulted, and preferentially oil-wet reservoir. Crestal gas injection (GI) in Mauddud has continued to be the dominant drive mechanism since 1938, making it the first improved recovery project in the Arabian Gulf region. This paper summarizes the performance of nearly 84 years of gas injection in Mauddud reservoir.
Performance-based analysis is carried out using different analytical techniques to determine voidage replacement and maximum gas-cap expansion rate to avoid gas overrunning and injection requirements. Volumetric sweep is estimated using volume of gas injected and gas cycled. Recovery is calculated based on material balance analysis using hydrocarbon pore volume (HCPV), gas injected, free gas-cap volume, and volume of residual oil in gas-cap (VOR). Semilog analysis of free gas/oil ratio (GOR) versus cumulative oil (Np) yields swept pore volume and moveable oil in different areas. Gas management strategy is devised based on wells to be shut-in, cut-off GOR, oil deferred, gas cycling limit, and remediation of high GOR wells with gas shut-off workovers. Optimum number of infill wells is evaluated based on NPV (net present value) for both vertical and horizontal completion.
Gas injection gravity drainage is an efficient mechanism in the Mauddud reservoir. Based on gas expansion rate to avoid gas overrunning, maximum GI rate is 652 MMscf/D. The volumetric sweep by gas is around 80%, giving a 50% recovery in gas-invaded areas. Critical gravity drainage oil rate per well is 383 STB/D. The average cycling of gas was 60% initially during 1970's, declined to 50% during 1986 to 2000, and currently increased to over 80%. The cumulative gas cycling is around 70%. Areas B, D, G, and H have the highest remaining mobile oil and should be the focus for infill drilling. A GOR cut-off of 80,000 scf/STB involves 97 wells, resulting in a gas reduction of 200 MMscf/D and an oil rate of 1,600 STB/D. A curtailment of free gas production of 100 MMscf/D will reduce the gas cycling from 87% to 70%. Cased hole horizontal well trial is promising based on workovers of open-hole horizontal well and newly drilled horizontal well trial with cemented liner. The development of Mauddud with a mix of both deviated/vertical and horizontal wells will reduce the number of wells in the tight spacing drilling campaign and provide robust economics. The methodology and analytical techniques described in this paper can be used for performance-based analysis of a large immiscible gas injection project.
An Ensemble-Based Infill Well Location Solution: A Cloud Native Application for Automating Well Placement and Evaluation
Authors: Pongtepupathum Wanida , Lang Philipp , Adeyemi Tobi 
Published: October 2022

Abstract
Field development planning moves from using deterministically constructed reservoir models to stochastically generated ensembles of models to better capture subsurface uncertainties. This leads to a challenge on how to understand reservoir dynamics and extract insights because of the large volumes of data involved. The objective of the presented system is to demonstrate how cloud-based computing can help to derive actionable insights of this large volume of data through automation, machine learning, and elastic scaling.
In this paper we present a cloud-native solution for optimizing and evaluating ensemble-based infill well locations. An opportunity index (OI) is derived from static and dynamic grid properties of reservoir simulation and a connected component search for every realization. Probability maps of OI are constructed to present the likelihood of high-OI areas from all simulations to propose infill well targets for the ensemble. Infill wells are automatically evaluated and ranked by ensemble field production increases. The workflow is deployed in a cloud-based system to leverage elastic scaling of compute resources to cope with the large volumes of data inherent in ensemble models.
The result from deploying this new workflow in a mature field in the North Sea shows that optimization of infill well targets at the ensemble level increases the robustness of targets compared to the alternative of selecting one or a few realizations. When randomly selecting two deterministic cases to analyze infill well locations, we observe inconsistency in candidate well locations. In case A, little opportunity is shown in the northern part of the reservoir and no opportunity in the southwestern part, whereas the result from case B shows almost the opposite, having a large area of opportunity in the northern part and a small opportunity in the southwestern part. By applying the proposed solution, only focused areas of the northern part of the reservoir are suitable for candidate well locations. The study time of target identification and evaluation is significantly shortened. The cloud-based deployment removes the company's need to own and manage powerful computer and data-storage infrastructure. In summary, the solution improves the workflow efficiency and provides high-quality results for field development decision making.
Lessons Learned from Implementing Smart Liners for Improved Matrix-Acid Stimulation of Carbonate Reservoirs
Authors: Mogensen Kristian , Al Hosani Fahad 
Published: October 2022

Abstract
Smart Liners are based on the limited-entry liner principle, which consist of an uneven spacing of a limited number of small holes drilled through the liner to mechanically divert acid along the entire reservoir drain. Past deployments have concentrated on extended-reach wells for which no other efficient matrix-acid stimulation techniques exist. With more than 100 deployments last year, ADNOC has significantly expanded the operational envelope in terms of pump rate, hole size, and well length.
Results from the Smart Liner implementation have been very encouraging so far. The general observation is that long-term productivity or injectivity is doubled, sometimes tripled, and the entire wellbore contributes to flow, documented by pre- and post-stimulation production logging. The technique has been successfully applied to several oil producers and water injectors, as well as to one gas producer, and yields superior well performance also in situations where conventional techniques can be deployed.
A number of points are worth highlighting: The technique is well-suited for both short and extended-reach wells; however, hole spacing designs strongly depend on the well lengthThe technique works for carbonate rocks of different lithology, such as limestone and dolomite (in addition to numerous chalk applications documented in the literature)Heterogeneity can to some extent be mitigated by appropriate placement of swellable packers and adjustment of hole density prior to stimulationThe high jet velocity through the small holes provides the right initial conditions for wormhole propagationFor water injectors, a pre-stimulation baseline injection period that cools the near-wellbore region in high-temperature reservoirs may improve the wormhole propagation.
The rapid deployment of this technique as well as the scale of implementation is unique in the industry.
Enhancing CO2 Foam Viscosity and Stability at Harsh Reservoir Conditions Through the Synergetic Interactions of Surfactant and Polymer
Authors: Al-Darweesh Jawad , Aljawad Murtada Saleh , Kamal Muhammad Shahzad , Al-Yousef Zuhair , Mahmoud Mohamed 
Published: October 2022

Abstract
The injection of foam into petroleum reservoirs has attracted special interest in the last decades. Some applications include; fracturing, stimulation, and gas mobility control during gas EOR processes. Utilizing foam in well stimulation is promising as it consumes less water than water-based fracturing fluid, is less damaging to the formation, and provides an effective proppant carrying capacity and transportation. This paper studies the synergic effects of surfactant-polymer system on the rheology and stability of foamed acid at high temperature.
A modified high-pressure, high-temperature (HPHT) foam rheometer was utilized to measure the apparent viscosity of CO2-foamed acid at 1,000 psi and 120 ℃. Additionally, a novel HPHT foam analyzer was used to characterize the following parameters; foamability, foam stability, foam structure, bubble count, and size under the same conditions. HPHT foam analyzer allows detecting the height and structure of foam all together as a function of the foam decay. Surfactant screening showed that Armovis is thermally stable at high temperatures and therefore was used in this work.
Results showed that the polymer enhanced the foamed fluid viscosity significantly. The apparent foam viscosity increased by 43 %, once 0.5 wt% of superpusher polymer was synergic with 1 % Armovis-surfactant. The results of the HPHT foam analyzer indicated that the Armovis/polymer system is thermally stable and capable of resisting high salinity. The foam half-life improved by 12 times when 0.5 wt% of the polymer was added. Also, the bubble growth rate reduced remarkably, this improvement was due to the adsorption of surfactant and polymer molecules at the gas/liquid interface, which resulted in the reduction of gas permeability through the liquid film.
This study investigates the synergy of polymer (superpusher SAV 522) and foamer (Armovis) in enhancing CO2 foam viscosity and stability at high pressure, temperature, and salinity. Furthermore, the surfactant-polymer systems evaluated can be investigated and used as stimulation fluid systems at temperatures up to 120 °C.