bluuebunny/crossref_metadata_2025_split huggingface dataset:
Managing Adequate Gas EOR for Unstable Asphaltene Stability Field - Asphaltene Flow Assurance Pre-Risk Assessment Case Study for CO2, Enriched Gas, and Lean Gas Options
Authors: Tange Masaaki , Hiraiwa Takeshi , Tareq Khlaifi Khuloud , Sakurai Risa , Bahri Sami , Abed Abdalla Abdelfattah , Uematsu Hiroshi , Makishima Ken , Inokuma Yuto , Sawata Masaru , Alkaabi Sultan Hamdan , Yonebayashi Hideharu 
Published: March 2023

Abstract
To enhance oil production (EOR) in tight carbonate oil reservoirs, gas EOR can be a promising option from injectivity viewpoints compared with water-basis chemical EOR. CO2 is the most attractive injectant with higher recovery factor expectation while responding to the recent decarbonization demands; however, CO2 is also known to accelerate asphaltene flow assurance risks. In actual fact, the previous work revealed a high asphaltene flow assurance potential risk for CO2 injection. Therefore, a further pre-risk evaluation case study was conducted to extract adequate type of potential injection gas among CO2, enriched gas, and lean gas.
This study focused on subsurface gas-induced asphaltene risks in an offshore heterogeneous oil field showing unstable asphaltene colloidal instability index (CII=2.2), where a crestal lean gas injection has been applied without any asphaltene issues. A single phase bottomhole sample was taken from appropriate candidate well keeping representative reservoir fluid in a clear asphaltene-gradient field: i.e., lesser asphaltenes in shallow depth but more in deeper section.
As a result of this study, no asphaltene onset was detected from original reservoir fluid while asphaltene onset pressures (AOPs) were detected from mixture of reservoir fluid and CO2 or enriched gas or lean gas at two temperatures representing reservoir and wellhead conditions. Experimental gas mixing ratios were carefully designed to distribute the AOPs broadly in operating pressure range: from in-situ reservoir and near wellbore to bottomhole, for securing higher numerical model accuracy by avoiding data extrapolation. A numerical model, calibrated with experimental outputs, predicted risk magnitude by reservoir depth. A comparative analysis revealed higher asphaltene precipitation risks in CO2 injectant than enriched gas and lean gas. Finally, asphaltene particle/aggregate size were discussed for formation damage risks. The visually measured asphaltene solid particle size varied from 1-10 μm for CO2 injection and 1-4 μm for enriched gas injection while no visible for lean gas. From the past injection water quality analysis, the reservoir has threshold particle size between 0.5-1.0 μm to cause plugging. Therefore, it was concluded that risk of asphaltene-induced formation damage is lower in enriched gas injection compared with CO2 injection. In general, higher oil recovery is expected by order of CO2, enriched, and lean gases.
In conclusion, even CO2 EOR is being attractive rapidly from decarbonization viewpoints, the study highlights an importance of balancing business case opportunity and risk from the aspect of injection gas-induced asphaltene flow assurance potential risks.
A Breakdown Pressure Prediction Model with Borehole Geometry Effect Considered
Authors: Han Yanhui , Almutawa Mustafa , Chen Shengli 
Published: March 2023

Abstract
Recently a set of engineering charts have been developed for the time-dependent stress and pore pressure responses at the wellbore surface under the ramp-type, finite-length fluid injection conditions, based on a semi-analytical solution with the use of Laplace-Fourier integral transform technique, to facilitate the prediction of borehole breakdown pressure for hydraulic fracturing operating practice. The charts were presented in a non-dimensionalized form to cover a wide range of borehole/rock parameters, which, in combination with the approximate solution for the impermeable borehole drilling problem, can be conveniently utilized to gain a rapid estimation of breakdown pressure. In this work, a borehole breakdown pressure prediction software was developed to generalize the applications of these engineering charts. Firstly, the engineering charts for an arbitrary borehole interval length-to-radius ratio are constructed from these charts by interpolation or extrapolation. Secondly, the breakdown pressure for a given borehole, in-situ condition, formation properties and pumping schedule, is looked up automatically with higher accuracy and faster speed than the method adopted in previous work.
Restoring Well Integrity: The Innovative Design of Thermally Activated Resin in a Sour Environment
Authors: Khan Danish Ahmed , Acuna Manuel Centeno , Hasan Salah Islam , Merino Lizeth , Chica Pablo , Hussein Ahmed Mudheher , Al Fakih Abdulqawi , Alo Rasho , Normann Svein 
Published: March 2023

Abstract
Loss of Well Integrity introduces the risk of uncontrolled release of formation and well fluids throughout the lifecycle of well. In a Southern Iraq field, one of the wells presented a rather unique challenge that when testing the production liner to 3000 psi, the pressure immediately dropped, and therefore, the integrity of the entire well was compromised. Pressure testing confirmed that the leak was through a liner coupling and USIT log showed that there was almost no cement bond behind the liner in the leak zone. The challenge was to find a safe and cost-effective solution to isolate and repair the hair-line leak, but also to find a solution that caters to the sour environment of the field itself, and that can last for the production lifespan of the well. A tailor-made thermally activated resin was designed in the lab to build a high compressive strength and durability and was not prone to cracking as the target treatment interval would be subjected to a pressure test as part of the conformance analysis.
Conventional approaches to repair this type of leaks, such as microfine cement, are prone to deterioration and cracking over time by which well integrity is compromised. Comparing mechanical barriers such as casing patches or straddle packers were considered as backup solutions as they interfered with production requirements. Downhole Circulating temperature was carefully modeled to avoid premature setting while pumping or delayed gelation of resin once exposed to bottom hole static temperatures. The pill was then squeezed into the leak path utilizing the Bradenhead methodology and the squeeze pressure was maintained throughout the duration of the gel time of the engineered design and the plug was then allowed to fully cure. Once cured, the plug was tagged where expected and milled down to just above the bridge plug. The target treatment interval was then subjected to multiple successful pressure tests confirming the restoration of well integrity.
Superactive Surfactant for Enhanced Oil Recovery
Authors: AlRadhwan Azizah , Hamad Mohammed Al , Abdallah Wael 
Published: March 2023

Abstract
After primary and secondary oil recovery, a large amount of oil is left behind in the reservoir. Enhanced oil recovery (EOR) techniques are introduced to recover additional oil from the reservoir. Chemical EOR is one of the commonly used EOR techniques. It involves the use of chemical substances such as surfactants. Surfactants are commonly used in the petroleum industry because they have the ability to change the water-oil interface as well as the properties of the rock surface. The use of such surfactants depends on technical, financial, and environmental factors. In this study, the performance of a new superactive surfactant is evaluated for use as an oil recovery agent for carbonate and sandstone formations. The surfactant showed high stability in deionized water and seawater, with strong ability to lower the interfacial tension of different crude oils (light, medium, and heavy) at a very low concentration (i.e., 0.05 wt%). The maximum reduction in interfacial tension reached 99.5%. The surfactant also showed significant surface wettability alteration toward water-wet at the tested concentration, with maximum reduction of 87%. From the interfacial tension and wettability experiment results, the optimum system was obtained for the medium crude oil and seawater at surfactant concentration of 0.05 wt%. Therefore, the coreflooding experiments on carbonate and sandstone samples were carried out using this system. Results showed a significant additional oil recovery by the surfactant injection. Additional oil of 43% was recovered from the carbonate core samples, while 16% recovered from the sandstone sample. With these results, this new surfactant can be potentially considered as a new agent for enhancing oil recovery from carbonate and sandstone formations.
Novel Shear Dependent Cement Slurry System, Tailored to Rescue and Cure Losses when ECD Management and LCM Pills Failed – A Case Study from Southern Iraq.
Authors: Campana Barbosa Lucio Felipe , Iqbal Javaid 
Published: March 2023

Abstract
The southern oilfields of Iraq have primarily two rock formations that stand out regarding how to manage fluid losses. The two formations have fluid losses due to their natural vugular porosity in the intermediate section, and additionally, a production zone that presents losses while drilling, thus compromising the hydraulic isolation of the reservoir and validating a dependable barrier above the production zone. The average well profile in this region of the country has a hole size that is usually drilled across these formations of either 17 ½" or 12 ¼" for the first and second loss zones and 12 ¼" or 8 ½" for the third loss zone. This situation renders the conventional solutions to cure losses less likely since the treatment entails a massive quantity of materials to attain success, typically after one or two unsuccessful attempts. For three consecutive years, a thixotropic and acid-soluble cement-based lost circulation treatment shave been ranked as the preferred solution by the operators drilling in these fields. This solution can be pumped through the drilling BHA, it does not exhibit mixing complexities, it is acid soluble, and eventually develops tailored compressive strength which prevents an accidental sidetrack.
The stratigraphic column of Southern Iraq has within the first 2,500 meters of depth the Dammam, the Hartha, and the Mishrif formations, which are highly susceptible to lost circulation problems, and ineffective treatment can lead to an increased rig time and accidental sidetracks. This paper describes how this preferred treatment is effective and how to evaluate well conditions to select the treatment volume, explains the regular job execution procedure, and breaks down the key parameters that the treatment fluid needs to demonstrate to maximize the chances of curing losses in the first attempt, enabling rig time and cost savings based on the historical cases from jobs performed in the Zubair and Rumaila fields.
Scale-Up Fabrication and Microfluidic Evaluation of Janus Graphene Nanofluids as Novel EOR Agent
Authors: Wang Wei , Chang Sehoon , Thomas Gawain 
Published: March 2023

Abstract
Nanofluid flooding is an emerging enhanced oil recovery (EOR) technique whereby injection fluids containing nanoparticles or nanocomposites are utilized for the oil displacement or injectivity improvement in oil reservoirs. However, current nanofluids with conventional nanoparticles have relatively low efficiency for EOR at simulated reservoir conditions, especially at low concentrations of nanoparticles. This research reported a new cost-effective method for scale-up synthesis of Janus graphene nanosheets and demonstrated a new type of nanomaterials, Janus nanofluids, as highly effective alternative nano-agents for EOR applications. A lyotropic liquid crystal phase as a novel "interfacial nano-reactor" system has been developed for fabricating Janus nanomaterials at nano-scaled liquid-liquid interfaces. Compared to interfacial reaction in a conventional bi-phase system, the new "interfacial nano-reactors" could tremendously enlarge the interfacial area by more than million times for chemical reactions at the interface, and thus allow production of Janus nanomaterials in mass quantity economically for industrial applications. Janus graphene nanosheets synthesized via this method have been characterized and confirmed by multiple techniques including scanning electron microscopy (SEM), Langmuir-Blodgett (LB) isotherm, contact angle, and interfacial tension (IFT) measurements. Interfacial tension measurements have shown that the Janus graphene nanosheets could significantly lower the IFTs between brine and crude oil at simulated reservoir conditions. With low concentration of Janus graphene nanosheets in nanofluid formula, microfluidic flooding experiments have been performed to evaluate the efficiency of the nanofluids for oil displacement in carbonate reservoirs. The results have demonstrated improved efficiency of oil recovery by the novel Janus graphene nanofluids at ultra-low concentration (0.01 wt%).
Fracture Characterization and Modeling in Dual Media Systems and its Impact on Reservoir Connectivity and Well Productivity
Authors: Al Mulhim Abdulrahim K. , Alnasser Mohammed H. , Hamam Hassan H. , Maucec Marko 
Published: March 2023

Abstract
A successful field development plan relies heavily on comprehending various subsurface complexities and their impact on the petroleum system. Hence, reservoir modeling plays an essential role in aggregating the complex systems and incorporating uncertainties. In the past decades, fracture characterization and modeling has advanced significantly in providing a high-resolution depiction of the subsurface. This paper focused on examining the impact of major fractures on reservoir connectivity and well productivity.
Fracture modeling and parameterization were performed using a synthetic dual porosity, dual permeability (DPDP) simulation model that was based on SPE10 model. Various deterministic fracture realizations were generated by incorporating multiple scenarios of different features such as fractures, high-permeability and high-flow feature planes, and layer bound fractures. The positioning of major longitudinal and lateral fractures was examined to analyze their role on reservoir connectivity and well productivity. Special focus was devoted to evaluate the impact of limited vertical and horizontal fracture extensions compared to more conventional workflows where fractures are modeled as planes across the entire reservoir. Furthermore, additional operational conditions, such as variable water injection schemes and depletion strategies, were applied to assess their impact on the model's response.
The evaluation provided in-depth analysis of various subsurface flow scenarios with DPDP systems. The characterization and modeling of complex subsurface features enhanced the understanding of spatial flow dynamics and their impact on reservoir performance. For example, layer-bound fractures result in different dynamic behavior compared to the ones crossing the entire reservoir. Additionally, high-flow features like high permeability streaks alter subsurface flow dynamics by accelerating fluid movement. Therefore, production analysis was performed for every scenario independently to benchmark the impact of various fracture parameters.
The paper provides comprehensive evaluation of fracture parameterization on subsurface dynamics by utilizing a DPDP SPE10 model to determine the distinct fracture signatures of reservoir performance and their influence on the overall hydrocarbon recovery.
Zero Losses Implementing a Heavyweight Engineered Spacer While Cementing a Rotatable V0 Expandable LinerHanger
Authors: Contreras Nino Adriana , Alabbad Mahmoud , De La Cruz Alejandro , Hugentobler Kory 
Published: March 2023

Abstract
The high-pressure/high-temperature (HPHT) environment poses different challenges for a cement design. In addition, there are challenges with the tight annular clearances across the liner overlap with the previous casing, and then finally achieving the desired top of cement. Engineering solutions and best practices can be implemented to overcome the challenges encountered while cementing under these conditions. A heavyweight engineered spacer with loss circulation material and an expandable-rotatable liner hanger were key components of the success.
Thoughtful analysis of the equivalent circulating density (ECD) resulted in the design of the train of fluids with a density difference of no more than 0.5 ppg. However, to overcome the risk of losses, an engineered spacer with a tailored load of its main component based on extensive lab testing was used. The weighting agent was carefully selected to ensure stability and rheological hierarchy. The cement job was performed with backside pressure applied with Managed Pressure Cementing (MPC) to keep a constant downhole pressure. To improve displacement efficiency and enhance cement bonding, an expandable liner hanger was rotated throughout the entire job and set afterwards.
The best practices implemented to cement the 9 5/8in liner resulted in performing the cement job without losses or flow. The ECD was kept within 5% from the mud weight density, based on the pressure match simulation. No abnormal pressures were observed while pumping and displacing indicating no settling issues were endured with the engineered spacer. Additionally, the liner hanger's unrestricted bypass area assisted in reducing the ECD's as no slips were required to keep it in place. The liner hanger was successfully rotated at 15 rpm throughout the job providing good cement placement. After the cementing job, the Liner hanger expanded successfully which confirmed the liner top integrity with a metal-to-metal seal. The expandable liner hanger also allows for less leak paths in the system along with providing high sealing and loading capability in high temperatures with a gas tight seal rating. After the wait on cement (WOC) time, the positive and negative tests were performed successfully meaning that a sustainable barrier was achieved.
This paper describes a success story while cementing under HPHT conditions with very narrow margins between pore pressure and fracture gradient and depicts the best practices that contributed to the success of the job, such as using a heavyweight engineered spacer with LCM and an expandable/rotatable liner.
Synergistic Hydrate Inhibition by Iota-Carrageenan with Kinetic Hydrate Inhibitors
Authors: Suri Ajay , Singh Ankur 
Published: March 2023

Abstract
The hydrate-inhibiting performance of a natural plant-based polysaccharide iota-carrageenan is evaluated as a standalone inhibitor and as a synergist with two well-known kinetic hydrate inhibitors (KHIs), polyvinyl caprolactam (PVCap) and polyvinylpyrrolidone (PVP), in order to achieve a higher hydrate inhibition performance. The hydrate inhibiting performance is assessed experimentally by measuring the induction time (IT) required for measurable hydrate formation and by the average hydrate growth rate (HGR) after measurable hydrate formation using a standard constant cooling rate of 1°C/h. Three inhibitor dosages at 0.5 wt% and 1 wt% are tested for the methane hydrate formation at 7.6 MPa and hydrate equilibrium temperature of 10.45°C. Synergy evaluation between the common KHIs and iota-carrageenan is done by making 50:50 ratio blends of iota-carrageenan with PVP and PVCap respectively (half iota-carrageenan and half KHI by wt%) and their performance is compared with the performance of individual PVP and PVCap performance at the same total inhibitor concentration for fair comparison. The individual inhibitor experimental results at 0.5-1 wt% showed that iota-carrageenan has a lower IT (around 4.5-5 h) than PVP (around 5.5-6.3 h) and PVCap (around 6.5-7.1 h), but has a lower average hydrate growth rate (HGR) between 0.07-0.08 m/h compared to PVCap (0.11-0.12 m/h) and PVP (0.13-0.18 m/h). The experimental results for the 50:50 blends of i-crgn with PVP and PVCap at a total concentration of 0.5-1 wt%, showed significant boost in the ITs (8.1-10.2 h for PVP and i-crgn blend) and (8.7-11.2 h for PVCap and i-crgn blend). These values were up 33-57% at the same total concentration of the individual inhibitor and the blend. The blends also have a much lower HGR with values 0.04-0.12 m/h at a total concentration of 0.5-1 wt% which is 16 - 64% lower than the individual HGRs of PVP and PVCap. Hence, iota-carrageenan, a natural, non-toxic, sustainable chemical can be used as hydrate inhibiting synergist additive to PVP and PVCap and other commercial hydrate inhibitors for enhanced hydrate inhibition performance and biodegradability.
Graph-Based Temporal Process Planning and Scheduling for Well Drilling Operations
Authors: Pavlov Maksimilian , Bukhanov Nikita , Safonov Sergey 
Published: March 2023

Abstract
Well construction is the most expensive stage of oil field development. Oil and gas companies carefully calculate all possible expenditures to assure that the project of well construction and exploitation will be profitable in time. The time for every operation of well construction is strictly regulated. However, in different oil and gas companies time allotted, for example, cementing surface casing or tripping operations can differ significantly. Therefore, some oil and gas companies are unable to calculate their well construction expenses accurately and lose a significant amount of money, which can be reduced. Also, engineering teams spend a substantial amount of time developing a drilling plan for the drilling crew, which may also be fully or partially developed by automated means. We present a data-driven approach for automatic planning and scheduling of drilling operations on wells with similar design and geological characteristics, suggesting also an improved operation classification based on the IADC dictionary of drilling operations.
The model for drilling operations planning is based on the directed graph traversal and process mining techniques. The algorithm takes as an input an undetailed plan, the section which is planned to be drilled, and the phase of well construction (drilling, cementing, logging). The algorithm selects the shortest path between two adjacent operations, gathers all paths together, and outputs a detailed plan with the corresponding time for each operation. For directed graph construction, we processed about 15 drilling reports from wells of a particular oil field which have similar well design and geology conditions by virtue of their geological proximity.
Algorithm performance was estimated by comparing graph time against similar plan time which was calculated based on the median time of every operation in a whole dataset. Median time (P50 percentile) was used because it demonstrates objective time in terms of well construction operations. We conjecture the above based on the fact that in some cases time for tripping can be faster or slower in some wells due to geological or other conditions, and the median provides an outlier-robust estimate of the average value. Also, graph time was compared between the engineering team's proposed plan and the actual time from drilling reports. Graph construction quality was estimated using three principal metrics: the Jaccard coefficient, structural distance, and fitness similarity.