bluuebunny/crossref_metadata_2025 huggingface dataset:
Clay Swelling Mitigation During Fracturing Operations Using Novel Magnetic Surfactants
Authors: Tariq Zeeshan , Murtaza Mobeen , Kamal Muhammad Shahzad , Shakil Hussain Syed Muhammad , Mahmoud Mohamed , Al-Jawad Murtada
Published: February 2022

In unconventional tight sandstone formations, due to the presence of clays, the fracturing operations may not be effective because of the clay swelling. The fracturing stimulation is the most used treatment method to produce from such kinds of reservoirs. The swelling of clays caused additional pressure to drop. Prior knowledge about the clay swelling behavior of the rocks with the fracturing fluid can reduce the risk associated with productivity issues. If swelling occurs at the rock's surface, it adversely affects the conductivity of the fractures.

This study proposed novel synthesized magnetic surfactants as a solution for the swelling of clay in hydraulic fracturing treatment. Several coreflooding tests were run using sandstone cores containing a significant proportion of the swelling clays. The permeability was assessed earlier and afterward the coreflooding tests. A scanning electron microscope (SEM) was run before and after the coreflooding experiments. The performances of magnetic surfactants were matched with the well-known clay stabilizing agents including NaCl and KCl.

Permeability measurement after coreflooding experiments revealed 90% permeability lost for the samples mixed with conventional clay stabilizer when post-treated with Deionized Water. On the other hand, the fracturing fluid containing magnetic surfactant solutions as clay swelling stabilizers reserved the initial permeability even post-flooded with DW. It was observed that the conventional clay stabilizers do not provide long-term stabilization of the swelling, while magnetic surfactants retain the permeability for long hours even being interacting with fresh water.

Magnetic surfactants have not been used as swelling inhibitors in fracturing fluids. This is the first study that reports the use of magnetic surfactant in clay swelling inhibition.
3D Inversion and 3D Anisotropy Analysis Improve Real-Time Decision-Making Process in Complex Clastic Reservoirs
Authors: Alkhars Abdulaziz , Achong Christon , Fouda Mohamed , Bikchandaev Eduard
Published: February 2022

Utilizing real-time integration of logging data with innovative 3D inversion and 3D anisotropy datasets, we present an innovative technical workflow highlighting powerful discrimination between oil-bearing sands, water bearing sands, and shale. Successful deployment in several challenging examples robustly reduces the uncertainty of the lithological and fluid analyses in complex clastic reservoirs.

3D Inversion of resistivity and anisotropy improves understanding of fluid distributions and reservoir architecture surrounding the well bore, improving the geological model and distribution of lithology for the field. This can be used to optimize geosteering processes for current and future wells. Integrated interpretation with other LWD data gives qualitative and quantitative information both near the wellbore and within the depth of investigation of the tool. Based on the difference in the Rv/Rh ratio for shale and sand, it is possible to resolve low resistive shale from the Oil Water Contact (OWC) at a distance. Additional interpretation of results provides valuable inputs for completion design optimization and reservoir management strategy updates. This will have significant impact in complex brownfields where reservoirs can possess variable water heights due to production.
Role of Geomechanics in Successful Pilot Evaluation of Unconventional Play in Kuwait
Authors: Gezeeri T. M. , Al-Sabea S. , Shinde A. L. , Perumalla S. V. , Govind Rao D. , Kerrouche N. , Memiche L. , Haddad C.
Published: February 2022

Lower cretaceous unconventional play in Kuwait comprised of majority of Carbonate with a maximum of 15% clay content. Kerogen-rich intervals present in the formation has hydrocarbon potential. However, the rock has very low matrix porosity and permeability and may not flow by itself. This paper discusses the pilot project of this play including formation evaluation and data integration to characterize the geomechanical sweet spots.

Highly deviated well in minimum horizontal stress direction was drilled through this unconventional target formation. No major wellbore instability was noticed while drilling this well. Comprehensive log data acquisition plan was made which included basic logs, image logs, formation pressure measurements, advanced acoustic and deep shear wave imaging. 1D geomechanical model was built by integrating information from drilling, geology, petrophysics and reservoir engineering. This model was calibrated against failure from Image and Caliper logs. Furthermore, wellbore instability events were also calibrated with the model produced failure. Natural fractures were interpreted not only from image logs (on wellbore wall) but also from ‘deep shear wave imaging (away from the wellbore)’. Critically stressed fractures (CSF) analysis was carried out using the fracture interpretations from image logs and geomechanical modeling.

It has been observed that at present day in-situ stresses and pore-pressure profile, some of the optimally oriented natural fractures are critically-stressed (which are hydraulically conductive). Production logging was carried out in an open hole and flow of hydrocarbon was recorded naturally. Hydrocarbon production from production logging matched very well with zones of critically stressed fractures, thereby establishing the role of stress-sensitive natural fractures on production optimization in such low permeable reservoirs.

Using integrated Sub-surface and Geomechanical characterization, hydrocarbon was unlocked from unconventional reservoir in a pilot well. Natural fractures interpretations from deep-shear wave imaging has added significant value and played key role to maximize the production from such low permeability unconventional reservoir. This finding has developed insights on field development strategy that has to include the natural fractures and geomechanics for enhanced production.
Novel Valve Condition Prognostic System for Digitally Enabled High-Pressure Pump Maintenance
Authors: Gerber David , Thaduri Jagan
Published: February 2022

The valve condition prognostics (VCP) system detects anomalies on high-pressure pump fluid-end valves and seats during fracturing before a total functional failure occurs. The VCP enables condition-based fluid-end replacement instead of time-based maintenance intervals, thereby minimizing downtime and maintenance cost and increasing asset utilization while eliminating permanent fluid-end damage due to operating with leaky valves. This is a step change when compared to the fixed-interval maintenance system.

The VCP includes the programmable logic controller (PLC), analog and digital modules, a rotation monitoring encoder connected to the power end, and pressure transducers to monitor fluid-end discharge and suction pressures. The intelligent algorithms feature robust failure prediction criteria based on machine learning [1], pattern classification [2], and adaptive algorithms, applicable to various equipment and field conditions. By obtaining ongoing and accurate pressure signatures, the VCP detects warnings and alarms that are sent to the operators in real time for action. Based on the alarms and operating parameters, the pumps can be shut down automatically to prevent damage.

During multiple field tests, the VCP successfully extended usable valve life by at least 45% when compared to our current fixed-interval maintenance method. The VCP is 100% accurate in detecting a catastrophic valve failure and avoided fluid-end damage. The VCP kits are easy to install onto existing pumps using existing discharge and suction pressure sensors. The data are sent to the cloud, and high-frequency data are recorded in the PLC for detailed analysis as needed.

In contrast to the common replacement approach that is based on either a scheduled time interval or when an operational failure happens, the VCP can detect and notify when an anomaly occurs and performs maintenance only when necessary. The fixed-schedule maintenance approach replaces the valves and seats in a conservative fashion regardless of their condition, often leading to waste. In the failure-based maintenance situation, equipment damage often results, leading to devastating pump shut down and expensive fluid end replacement. The VCP addresses both challenges. It not only prevents prolonged and costly equipment failures, but also reduces downtime, valve and seat parts cost, and maintenance time.
Interpreting Downhole Esp Data for Predicting Production Performance by Use of Inversion-Based Methods in South Europe Field
Authors: Pignotti Eleonora , Spagnolo Salvatore , Pilone Salvatore , Baldassarri Gianni , Cappuccio Pasquale , Valente Alberto , Greco Pasquale , Gonzalez Zamora Mariangela
Published: February 2022

The objective of this paper is to demonstrate how a physics-based data driven model and inversion procedures can transform traditional ESP well monitoring into an indispensable tool for predicting multiphase flow rates in ESP production wells. Model and prediction techniques are evaluated by comparison with real field data, measured both live and retroactively from different ESP producing wells located in the South Europe producing field.

Operational data commonly gathered by ESP gauge, such as Pressures data, Motor Current and Operative Frequency can be used to predict flow through ESP components, without need for rental of expensive Well Testing equipment. The exploitation of a similar advantage is made possible by the application of artificial intelligence algorithm joined with physics based modelling, taking in as input ESP dynamic data and giving as output a simulation–with acceptable accuracy- of the continuous downhole flow and reservoir properties, allowing the oil operator to obtain key information to optimize well production based on the calculation of ESP operational point.

Such cost-effective metering technology is already suitable for online real-time systems implementation and has already been put in place in South Europe field, where it gives reliable results that will yield ongoing ESP run life improvement through its constant application. The improvement of several ESP KPIs, such as MTBF and MTTF, is strictly related to a more accurate follow up of the ESP operative point, hence of the ESP production. Higher ESP MTBF/MTTF might lead to a reduction of the number of necessary ESP replacement workover for year, thus causing the enhancement of hydrocarbon recovery and a reduction of the differed production.In addition to all of this, the possibility of virtual metering well production performance by means of a virtual model might provide a sensible reduction of the number of replacement systems provided from Service Companies, hence the overall optimization of production operation costs.

The increasing need for operational efficiency, cost reduction and improved equipment means that service life has driven the recent technological developments related to electrical submersible pump (ESP) well operation management. This paper well described the application and the benefits of such technology to be used as reference successful case by other key players in the O&G market.
Rigless Electrical Submersible Pump Deployment Power Cable Qualification Testing in High Flow Rate Oil Wells
Authors: Xiso Jinjiang , Ejim Chidirim , Banjar Hattan , Munif Eiman , Tulbah Faris , Sarian Serko
Published: February 2022

Objective / Scope

Conventional Electric Submersible Pumps (ESPs) are deployed using production tubing, service rigs and well killing services. In recent years load bearing Power Cable deployed ESP systems have been developed, eliminating the service rig and reducing ESP changeover time by more than 80%. More recently developed live well Cable Deployed ESP systems further eliminate the need for well killing services, and potential reservoir damage. The downside in both cases is for the power cable to remain inside the tubing and withstand long term production fluids.

A fit for purpose load bearing Power cable has been designed and qualified for reliable long term ESP operation in live sour oil wells.

This paper covers the abrasion testing and inspection results of the cable armor being exposed to long term high-rate and high-solid content production fluids.

Methods, Procedures Process

A prior finite element modeling (FEA) helped fine tuning the abrasion testing and inspection plans.

A section of cable prototype was enclosed inside a 20 ft long field production tubing and inserted into a 6000 barrels per day capacity flow-loop made of a fluid mixing tank, Triplex mud pumps and a 2″ flow choke and piping system. Two-phase accelerated testing was implemented using 130 bbls salt water @ 45,000 Mg/L NACL

In Phase 1, 4.3% by weight Limestone particles were added and pumped at 5,000 bbls/day

In Phase 2, solids content was increased to 6.5% by adding 1 metric ton (MT) Sandstone and 0.3 MT Limestone.

Results, Observations, Conclusions

Phase 1 and Phase 2 were 7 days each using 75% duty cycle pumping. Post-testing, the cable sample showed no visual deterioration. It was then sent to a specialized lab in the UK for microscopic inspection and yearly abrasion rates computation.

In Conclusion it was demonstrated that the cable design and selected armor alloys were adequate for the three re-deployment operational requirement (equivalent to 10 year continued operation in the well)

Novel/Additive Information

The Novel FEA analysis and accelerated solids abrasion testing process allowed for accurate real-well simulation and significant early de-risking of the project.
Review of Non-Metallic Pipelines in Oil & Gas Applications - Challenges & Way Forward
Authors: Bukhari Amer. O. , Bashar Mohammad , Aladawy Ahmed. S. , Goh Serena. L. M. , Sarmah Pranjal
Published: February 2022

Nonmetallic pipelines are gaining popularity across the Oil and Gas value chain from upstream to downstream applications. Among the top benefits are mitigation of corrosion hazards, lowering the total cost of ownership, and reducing carbon footprint. While nonmetallic pipes are increasingly deployed onshore and offshore, a focus on downhole tubular development and qualification is essential as these are lacking in literature. In this paper, the authors attempt to provide an overview of the technology status quo as well as highlighting implementation challenges on downhole applications and proposed a way forward to tackle such challenges.

A detailed literature review on current technological advancements and market trends of non-metallic pipes is carried out with a particular focus on downhole R&D potentials and application progression towards more severe well conditions, while meeting the future Oil and Gas demands. A comparison of current market offerings of non-metallic pipes for onshore, offshore, and downhole applications is conducted, based on their design construction, material compositions, pipe dimensions, and operating envelope. In light of such comparison, there is a market gap of the intended target specs for downhole applications. Pipe design, material selection, and product qualification are also described in the process to highlight the effort needed for industrial standards to qualify the downhole tubulars. Manufacturing of pipe and connectors are briefly discussed as part of the challenges.

A gap analysis is also conducted to address the downhole system and infrastructure challenges related to utilization of non-metallic components in drilling, completion, logging, intervention, and production conditions, as the existing qualification standards are not capable of adequately addressing the various possibility and combination of non-metallic pipe configurations and their components for the intended service conditions. This study identified the areas where R&D work is required for non-metallic pipes to be designed, tested, and qualified for application in demanding and aggressive well conditions (e.g., high temperature and pressure) in order to replace steel tubulars for improved properties.
Favorable Target Optimization for CO2 Flooding in Deep Block Sandstone Reservoir with Bottom Water: A Case Study of Northwest Oilfield M Reservoir
Authors: Xu Ting , Liao Haiying , He Yingfu , Nie Jun , Cui Maolei , Guo Yabing
Published: February 2022

Northwest oilfield M reservoir is deep block sandstone reservoir with strong aquifer, having thin layer, large water-oil volume ratio, high temperature and salinity, strong heterogeneity, being developed more than 20 years by depletion method, influenced by bottom water, reservoir comes into high water cut period, recovery degree is only 26%, requiring for further enhanced oil recovery technology. CO2 is easily miscible with oil, but whether CO2 is applicable for the reservoir with strong aquifer or not is still unclear. No foundation can be referred to in area optimization for CO2 flooding. It is necessary to conduct research on influencing factors of CO2 flooding in the sandstone reservoir with aquifer and set up the favorable target optimization technology.

Reservoir engineering method was applied to study M reservoir production pattern. Based on G&G, the geological-dynamic response law was established and productivity influencing factors were studied. Considering flowing differences between block reservoir and layered reservoir, the flowing field is affected by vertical sweep of bottom water, internal small faults have sealing effect on plane sweep, development unit division method was formed on the basis of vertical hydrodynamic characteristics. According to CO2 occurrence state and dynamic distribution in oil layer and strong aquifer, three types of favorable target have been classified, favorable target optimization technology is established for CO2 flooding in deep block sandstone reservoir with strong aquifer.

Research results show that the south and middle block are structurally high, edge water intrusion is weak, main layer is relatively thick and interlayer is developed, I and II type well are the main production well. While the north block is structurally low, reservoir quality is poorer, II and III type wells amount a lot. CO2 density is higher than the oil, in the interlayer undeveloped block, CO2 migrates vertically to the oil-water interface, then spreads laterally forced by bottom water, resulting in an increase in the oil-water interface tension and a decrease in the diffusion rate to the water. The more developed the interlayer is, the larger the sweep volume of CO2 is. In high structural position, fault sealing, interlayer developed and thick layer, the enrichment degree of remaining oil is still high, important to ensure CO2 lateral sweep. As results, favorable target for CO2 flooding is classified into I, II and III type.

CO2 flooding pilot test was carried out in type I favorable target. Till now, 18,000 tons of CO2 had been injected, oil exchange ratio in 1st year was 0.13. Research results lay the foundation for the efficient utilization of the remaining oil, so as to explore an effective development method for deep, ultra-deep sandstone reservoir to greatly enhanced oil recovery.
Advanced Multi-Physics Sensor Utilizing Molecular Fingerprinting for Production Logging Tool
Authors: Maity Sandip , Abrar Manzar Muhammad , Al-Shabibi Hussain , Jindan Jana , Larbi Zeghlache Mohamed
Published: February 2022

Knowledge of fluid density along with phase measurement are extremely important for reducing the variance in estimating the flow profile from the production logging tool (PLT). When both oil and water are produced simultaneously, induced reflectance measurement derived from the optical refractive index is not effective. This is mainly due to phase persistence behaviour of the optical sensor caused by the coating of the previous phases. The most effective way to characterize such flow is to measure the fluid's fluorescence along with refractive index and density. In this paper, a novel solution is presented using a piezo helm resonator sensor with simultaneous and congruent measurements of fluid mass density, viscosity and sound speed.
Pore Geometry Effect on Si, Trapping and Sor in Tight Carbonate Reservoirs
Authors: Kayali Anas , Koronfol Safouh , Gnozalez David
Published: February 2022

Spontaneous imbibition is one of the key production mechanisms in fractured oil reservoirs. It is also an important process in tight gas formations, which has significant effects on the gas production after hydraulic fracturing. The objective of this research is to investigate the effects of pore throat sizes and connectivity on spontaneous imbibition behavior in tight carbonate rocks. Many plug samples were selected from various wells in the Middle East. The samples were characterized using X-ray CT imaging, thin-section photomicrographs, Helium porosity and gas permeability. High pressure Mercury injection experiments (MICP) were performed in the primary drainage mode to obtain the pore throat size distributions, followed by Mercury withdrawal tests to investigate the spontaneous imbibition curve and fluid trapping. The degree of pore connectivity was studied in the samples from thin-section photomicrographs and from primary drainage capillary pressure curves and were found in good relationship with the Mercury withdrawal behavior and residual fluid saturations. Higher permeability samples were characterized by lower entry pressures that showed higher tendency towards lower fluid (Mercury) trapping.

These results show important link between the rock nature and spontaneous imbibition and fluid trapping that can be deduced from Mercury withdraw testing. Accurate prediction of spontaneous imbibition is crucial in many hydrocarbon reservoirs and such analyses help understand production mechanisms in different carbonate rock types.
Study and Implement of the Large Amount Data Divided Time Transmission System Utilizing Microchip-Storage-Ball Release While Drilling
Authors: Li Sanguo , Gao Ruixiang , Li Jibo , Zhu Zuyang , Wang Zhifa , Gramajo Silva Eduardo Davio
Published: February 2022

The more downhole information measured by LWD tools, the more measurement data they produces. The conventional LWD tools can hardly transfer all the large amount of data of LWD tools to the surface, which greatly limits its advantages in while-drilling production. If retrieved after drilling, certain LWD tools would lose their advantages entirely in while-drilling production. This paper proposes a novel method that employs the basic concept of a "flash drive" downloading and exchanging data among computers. A system is developed to achieve data transmission in a time-division manner using releasable microchip storage. The system includes a plurality of microchip storages, a plurality of sealed chambers each for containing a microchip storage, a release power device, and a circuit. The release signal is sent by time setting or pressure signal triggering. In drilling, the data measured by the LWD tools can be downloaded into the microchip storage. A release signal could be sent on time, or the release signal can be triggered and sent by the pump pressure pulse, when the LWD data is needed. Upon receiving the release signal, the circuit sends a release command to control the power device to release the microchip storage from the drill collar into the drilling fluid in the annular. The microchip storage can be carried to the surface by drilling fluid and can be recovered. The data in the microchip storage can then be retrieved. In this system, there are four contacts on the microchip storage to connect with the circuit, through which power supply and data connection are established. The data access to the LWD data complies with the RS485 data protocol. The system adopts a push technology. The data capacity of single microchip storage is 1 Mbit, and the size of which is 12mm (D)×12.5mm (H). One drill collar system can carry up to 24 microchip storages. Thus it makes a single collar system have a large data storage capacity. It can improve the efficiency of data transmission.
Newly Designed High Expansion Through-Tubing Bridge Plug Service to Reduce Operational Costs and Increase Reliability
Authors: Eyuboglu Sami , Heaney Frank , Chamarthy Pramod , Powell Bryan , Gullett Chris
Published: February 2022

Through-tubing bridge plug (TTBP) service is a common e-line well intervention service for isolating lower non-productive zones for improved production or plug and abandonment. Traditionally, this service was only run on e-line, as it requires a unique electro-mechanical extended stroke setting tool, to set these types of barriers. This paper discusses the challenges of developing a new design of the TTBP, deployed on Digital Slickline (DSL) to help optimize service costs.

System-level analysis was adopted to analyze the current e-line TTBP service and identify challenges to DSL deployment. In general, these plugs have extremely high-expansion ratios (2x to 4x) compared to other wireline set barriers as they have to pass through tight downhole restrictions in the completion before passing into the casing. As a result, these plugs have an exceptionally long setting stroke, requiring a specific setting tool with high power demands. The high expansion ratio of the TTBP limits pressure rating and this type of barrier demands a cement cap on the plug to complete the intervention. DSL cannot send power from the surface; therefore, it has electrical power budget limitations. The right balance needs to be found between the stroke length and the available power to achieve a successful plug.

The elastomer stack and the backup petal assembly were significantly redesigned to achieve an acceptable expansion ratio while minimizing stroke length. This feature allowed for the development of a battery-powered setting tool with a shorter stroke length. Running the service on DSL lets the operator confirm depth correlation before setting the plug and real-time feedback from downhole sensors to ensure an in-situ quality plug set. Moreover, digital slickline provides accurate bottom-hole temperature, which is critical in achieving a suitable cement plug. The paper will present results from field trials showing the cost savings of running these plugs on DSL compared to e-line.
Analytical and Experimental Study of Oil/water Emulsion in Multi Stage Electric Submersible Pump
Authors: Ridlah Muhammad Rasyid , Zhu Haiwen , Zhang Hong-Quan
Published: February 2022

The non-Newtonian behavior of oil/water emulsion in the ESP stage is still not well understood. The industry relies on existing empirical correlations, which only valid for production pipelines without considering the effect of shear force acting on the system. This paper will present the analytical modeling of emulsion rheology in the ESP stage and its effect on ESP boosting pressure. An extensive experimental data set validates the analytical model accuracy.

The Brinkman empirical correlation is the baseline of the analytical model development. Emulsion rheology in the ESP stage depends on many factors. Dimensionless analysis by the Buckingham-Phi theorem indicates that at least three parameters play an essential role in the emulsion rheology at the pump stage. Those parameters are concatenated and applied as the modified function of Brinkman empirical correlation. In addition, the pump boosting pressure performance observed experimentally to study the emulsion rheology effect at the ESP. More than a thousand experiment data points employed to test the proposed model, and its comparison is studied statistically.

The dimensional analysis prevails that the turbulence effect at the stage condition reflected by the Reynolds number, the droplet size effect represented by the Weber number and the Strouhal numbers relates to the shearing effect due to impeller rotation. The analytical model and experiment perform with two different oil viscosity, 45 cp and 70 cp. The results reveal that the higher oil viscosity reaches the inversion point at a lower water fraction since the turbulence decreases with higher oil viscosity. The emulsion rheology from the experiment result shows a significant increase of emulsion viscosity at water fraction close to the inversion point since the increase of hydrodynamic forces due to a higher number of water droplets. The emulsion rheology model aligns with the experiment results for the inversion point at around 35% and 32% water-fraction, respectively. The emulsion rheology model shows a good agreement with the experimental data with a 15% standard deviation of relative error. Increasing water fraction up to the inversion point deteriorates pump boosting pressure since the high friction loss occurs due to higher emulsion viscosity. Nevertheless, as the water fraction passes theinversion point, the boosting pressure starts to rebound as the water turns into the continuous phase. The formation of oil/water emulsion in the ESP is inevitable during production operation and consequently affects the pump boosting pressure. The inversion point phenomena occur at a different range of water fractions for different oil viscosity. A better understanding of emulsion rheology at the pump stage will lead to an accurate artificial lift design and eventually avoid operation failure during production well operation.
Design and Optimization of Autonomous Inflow Control Device in Water-Bearing Sour Gas Reservoirs
Authors: Zhou Chao , Zhao Xu , Chen Yashu , Wang Zhifa , Gramajo Eduardo , Rached Rached , Hu Changpeng
Published: February 2022

Autonomous inflow control device (AICD) completion has been applied in many conventional oil and gas reservoirs and has effectively controlled the water invasion. However, the method for designing and optimizing of AICD in sour gas reservoirs is still lacking. The objective of the proposed paper is to establish a numerical simulation and optimization method to evaluate and optimize the performance of AICD completion in water-bearing sour gas reservoirs. Firstly, a sulfur deposition saturation model is established considering non-darcy flow and stress sensitivity in sour gas reservoirs, meanwhile, time-varying skin factor is introduced to represent the influence of sulfur deposition on permeability. Secondly, a new type of AICD is designed, which has large flow channels and vortex chamber to satisfy the need of restraining water invasion and sulfur plugging in sour gas reservoirs. Finally, a reservoir-wellbore simulation method is established, which considers the sulfur deposition in the reservoir and the new AICDs in the wellbore, then the key parameters of AICD is optimized by orthogonal test and range analysis. The results of the numerical simulation show that the simulation and optimization method can effectively optimized the key parameters of AICD and the optimized AICD completion has good water invasion restriction capacity in water-bearing sour gas reservoirs. The optimized AICD completion causes little additional pressure drop compared to perforation completion in sour gas reservoirs, and the maximum additional pressure drop is less than 0.67 MPa, which means the optimized AICD completion is able to control water invasion as well as maintain normal gas production of sour gas wells. Besides, the optimized AICD completion decreases both the daily water production and the cumulative water production compared to perforation completion in sour gas reservoirs. In the last stage of the tenth year prediction period, the cumulative water production with AICD completion decreases by about 22.7% compared to that with perforation completion. In conclusion, the simulation and optimization method can be used for guiding the rational application of AICD completion in water-bearing sour gas reservoirs.
Novel Promising Metal-Organic Framework for the Decarbonization of Oil and Gas Utilities Sector
Authors: Alahmed Ammar , Younes Mourad , Jamal Aqil
Published: February 2022

The global demand for energy is on the rise and in order to eliminate the associated emissions, carbon capture utilization and storage is deemed as one of solutions to achieve this target.1 Furthermore, the development of renewable energy alternatives including: solar, wind, geothermal, etc., is one of the potential long-term options to eliminate additional emissions.2 Although electricity generation from renewable sources is on the rise, it is going to be a long journey for renewables to take over the traditional power generation routes.2
Modeling CO2 Sequestration in Deep Saline Aquifers – Best Practices
Authors: Alzayer Hassan , Zahrani Tareq , Shubbar Ahmed
Published: February 2022

Managing carbon emissions has become a major responsibility for the oil and gas industry in a drive to ensure sustainable energy and create a clean environment. Therefore, governments, research centers, IOC’s and NOC’s are actively adopting new guidelines and inventing new technologies to safely circulate carbons. In this paper, the process of modeling CO2 sequestration in a deep saline aquifer will be discussed.

Carbon dioxide can be safely stored indefinitely in subsurface geological formations by four trapping mechanisms; structural, residual, soluble, and mineral trapping. These four trapping mechanisms can take hundreds or thousands of years to happen. Furthermore, the oil and gas industry standard recommend that any technology used to store CO2 needs to demonstrate a storage capacity of 1000 years with less than 0.1 per-cent leakage potential per year. Therefore, modelling such process should capture any existing trapping mechanism, even if it happens after several hundreds of years, to ensure long-term secure storage of the CO2. Using our in-house simulator "GigaPOWERS", many sequestration scenarios were conducted to come up with a recommended guideline to maximize the volume of CO2 trapped in deep saline aquifers.

This study used a giant synthetic anticline model with a variation in geological properties. The residual and soluble trapping mechanisms were captured through relative permeability hysteresis and extended water PVT tables respectively. Injecting CO2 into water aquifers is a dynamic process where drainage and imbibition cycles are likely to happen. Such processes cause the CO2 to be trapped in the middle of the pores as an immobile phase, which can be a favorable phenomenon maximizing the security of CO2 sequestration. Since CO2 is soluble in water, when it contacts the water phase it will form a carbonated water that is denser than water itself and migrates downward in a phenomenon known as "CO2 fingering". The CO2 solubility in water depends mainly on the salinity and temperature which both need to be accurately captured in the simulation model. Depending on the long-term objective of the sequestration project, the development strategy can be altered to maximize the outcome using the detailed simulation model. In this paper, the simulation best practices for modeling CO2 sequestration for maximum secure long-term storage (1000+ years) are suggested.

Carbon dioxide, CO2, sequestration in deep saline aquifers is a well-known method to reduce carbon emissions. However, there is very little published literature on the simulation best practices for modeling the CO2 sequestration process. Therefore, this paper will be a pioneer to guide the industry for accurate simulation of such process.
Reservoir Characterization for Isolated Porosity from Multi-Frequency Dielectric Measurements
Authors: Jin Guodong , Ma Shouxiang , Antle Ryan , Al-Ofi Salah M.
Published: February 2022

Due to processes of geological diagenesis, pores in rocks can be isolated from the rest of the connected pore networks. The amount and spatial distribution of isolated pores can have direct effect on petrophysical properties and performance of the reservoir. This paper introduces a new methodology to quantify the isolated porosity of heterogeneous reservoirs from multi-frequency (dispersion) dielectric measurements. Based on numerical simulation studies, digital rock physics techniques are used to generate rock models with different isolated porosities. 3D dielectric dispersion modeling is then performed on the models to obtain the dispersion of rock’s dielectric constant. Dielectric dispersion behaves differently as the pore connectivity changes due to increase in isolated porosity. Dielectric constant is sensitive to frequency when pores are isolated, while insensitive to frequency when pores are connected.

Variation of dielectric constant is strongly related to the amount of isolated pores. For rocks having the same total porosity, their dielectric constant increases as the isolated porosity increases. This enhancement of dielectric constant is attributed to the increase in pore network tortuosity, resulting in increased accumulations of electric charges at the interfaces between solid and pores. Analytical relationships are developed to correlate isolated porosity with the rate of permittivity change and/or the permittivity ratio, derived from the dispersion of dielectric constants. The validity and applicability of the established method are demonstrated by the agreement of predicted isolated porosity with the true values used in building the rock models. Potentially, this method can be used for enhancing reservoir characterization with modern multifrequency dielectric logs.
Surface Modified Nanoparticles Based Novel Gelled Acid System - A Unique Formation Damage Free Well Stimulation Technology
Authors: Kalgaonkar Rajendra , Baqader Nour
Published: February 2022

Gelled acid systems based upon gelation of hydrochloric acid (HCl) are extensively used in both matrix acidizing and fracture acidizing treatments to prevent acidizing fluid leak-off. The gelled-up fluid system helps retard the acid reaction to allow deeper wormhole propagation. Conventional in-situ crosslinked gelled acid systems consist of a polyacrylamide polymer, a crosslinker (such as iron-based crosslinker), a chemical breaker, other additives, along with acid. However, these systems can lead to damaging the formation due to several reasons including unbroken polymer residue or scaling, resulting in lowering of hydrocarbon productivity. To mitigate these drawbacks, we have developed a self-breaking, formation damage-free, novel nanoparticles based gelled acid system to replace the polymer based gelled acid system. The new gelled acid system is based on, surface modified nanoparticles to make them compatible in acidic environment, a gelation activator, acidizing treatment additives along with HCl to overcome the challenges the conventional systems face. The new system can work with up to 28& of HCl up to 300°F with low viscosity at surface, making it easy to be pump. As the acid spends due to reaction with the formation the pH of the fluid transitions from acidic to basic pH. The gelation phenomenon of the new system is controlled by the increasing pH. As the pH increases beyond pH 1 gelation of the nanoparticles occurs thus gelling up the acidic fluid. As the pH further continues to rise beyond pH 4 the nanoparticles lose their capability to gel up and the fluid viscosity decreases to pre-gelation level, facilitating easy post treatment flow back.

A systematic experimental protocol was followed to develop the new system that is documented in this paper. It is shown that the gelation properties are pH dependent phenomenon providing the critical control over the gelation time and avoiding any premature gelation during pumping the treatment. The effectiveness of the system by not damaging the formation was investigated using regain permeability studies. The new system showed excellent regain permeability. The obtained data confirmed several advantages of the new system over conventional polymer based gelled acid systems. Gelation experiments were performed to gather a better understanding of the gelation mechanism and also to get effective control on the gelation and break properties.

The uniqueness about the new system is that, it is formation damage free without the need to use polymers or iron based cross-linkers that may lead to potential damage mechanisms.
Balanced Injection and Production Technique for Horizontal Wells Based on Inter-Well Connectivity
Authors: Zhang Yanhui , Zhang Hongyou , Liu Yingxian , Wang Shaomeng , Wang Chengcheng
Published: February 2022

Because of the long horizontal length and the reservoir heterogeneity, the water production and injection are different along different locations of a horizontal well. So the conventional water injection string are not suitable for horizontal wells. Besides, the conventional models for inferring interwell connectivity between directional wells are not suitable for horizontal wells. In this paper, a new model for inferring interwell connectivity between horizontal wells is built and a new water injection string for horizontal injector is presented which can meet the demand of water injection of different locations for a horizontal well.

Based on the conventional water injection string, a new packer was installed at water injection string with the location's deviation less than 60 degrees. A Water distributor working cylinder was installed to respectively distribute water to root and toe of a horizontal well. Inorder to characterize different sections of a horizontal well, a horizontal well can be considered as several directional wells with different physical properties such as permeability and porosity and so on. Based on this, the reservoir is characterized as a coarse model consisting of a number of interwell units which is controlled by any two directional wells. Injection and production data were used to infer interwell connectivity and geological characteristics.

The results obtained from the new proposed model are in consistent with the oxygen activation of injectors. Interwell connectivity coefficient of each injector were calculated and the preponderance flow paths were found. Based on this, profile control were conducted. After profile control, the water injection efficiency of horizontal injectors obtained by this model improved and water cut of produces was reduced by 9% ~ 10%.

This technique has been used in nearly 100 wells of Bohai oilfields. With the inter-well connectivity method and the balanced injection string for horizontal wells, the development effect of reservoir with horizontal wells improved significantly.
CO2 Storage Capacity Prediction In Deep Saline Aquifers: Uncertainty and Global Sensitivity Analysis
Authors: He Xupeng , Zhu Weiwei , AlSinan Marwa , Kwak Hyung , Hoteit Hussein
Published: February 2022

Geological CO2 sequestration (GCS) has been a practical approach used to mitigate global climate change. Uncertainty and sensitivity analysis of CO2 storage capacity prediction are essential aspects for large-scale CO2 sequestration. This work presents a rigorous machine learning-assisted workflow for the uncertainty and global sensitivity analysis of CO2 storage capacity prediction in deep saline aquifers. The proposed workflow comprises three main steps: 1) dataset generation — we first identify the uncertainty parameters that impact CO2 storage in deep saline aquifers and then determine their corresponding ranges and distributions. We generate the required data samples by combining the Latin Hypercube Sampling (LHS) technique with high-resolution simulations. 2) surrogate development — a data-driven surrogate is developed to map the nonlinear relationship between the input parameters and corresponding output interests from the previous step. The implementation of Bayesian optimization accelerates the tunning process of hyper-parameters instead of traditional trial-error analysis. 3) uncertainty and global sensitivity analysis — Monte Carlo simulations based on the optimized surrogate are performed to explore the time-dependent uncertainty propagation of model outputs. Then the key contributors are identified by calculating the Sobol indices based on the global sensitivity analysis. The proposed workflow is accurate and efficient and could be readily implemented in field-scale CO2 sequestration in deep saline aquifers.
Smart Predictive Maintenance Framework SPMF for Gas and Oil Industry
Authors: Alameldin Magdi
Published: February 2022

The O&G industry is facing big challenges which consequently raise the necessity for reforming its traditional business model and integrating digital disruptive technologies such as Digital Twins, Artificial Intelligence and Blockchain. A Digital Twin(DT) is defined as a dynamic intelligent digital replica/model of the physical system/process/service/people which enables just-in-time informed decision making and root-cause analysis using AI. DTs are implanted at different levels such as Equipment/Asset Level Twin, System Level Twin, System of Systems (SoS) Level Twin.

This research introduces a novel framework which is based on a Smart Secure Digital Twin (S2DT) to bridge the development gap compared to other leading industries such as manufacturing and automotive. The proposed model relies on Tiny Machine Learning (TinyML) to implement edge intelligence and solve the problems of transfer latency and data overload and consequently achieves low carbon footprint. Edge Intelligence (EI) reduces energy consumption and enhances security and perspective maintenance. The Blockchain Technology is used to solve the privacy, and cybersecurity problems [4]. The Extended Reality (XR) will be used to ensure proper training of operators, and industry 5.0 to boost collaboration between human and machine. At the component level, security is maintained by integrated the locally generated intelligence on a blockchain to insure immutability, and enhance security.